As filed with the Securities and Exchange Commission on
June 19, 2008
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
CVR ENERGY, INC.
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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2911
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61-1512186
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer
Identification Number)
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2277 Plaza Drive, Suite 500
Sugar Land, Texas 77479
(281) 207-3200
(Address, Including Zip Code,
and Telephone Number, Including Area Code, of Registrants
Principal Executive Offices)
John J. Lipinski
2277 Plaza Drive, Suite 500
Sugar Land, Texas 77479
(281) 207-3200
(Name, Address, Including Zip
Code, and Telephone Number, Including Area Code, of Agent for
Service)
With a copy to:
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Stuart H. Gelfond
Michael A. Levitt
Fried, Frank, Harris, Shriver & Jacobson LLP
One New York Plaza
New York, New York 10004
(212) 859-8000
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Peter J. Loughran
Debevoise & Plimpton LLP
919 Third Avenue
New York, New York 10022
(212) 909-6000
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Approximate date of commencement of proposed sale to the
public:
As soon as practicable after the
effective date of this Registration Statement.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box.
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If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
please check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering.
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If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
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Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large accelerated
filer
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Accelerated
filer
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Non-accelerated
filer
þ
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Smaller reporting
company
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(Do not check if a smaller reporting
company)
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CALCULATION OF REGISTRATION FEE
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Proposed Maximum
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Proposed Maximum
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Amount of
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Title of Each Class of
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Amount to be
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Offering
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Aggregate
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Registration
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Securities to be Registered
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Registered(1)
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Price per Share(2)
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Offering Price(1)(2)
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Fee
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Common Stock, $0.01 par value
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11,500,000
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$25.51
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$293,365,000
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$11,530
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(1)
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Includes the number of shares, or
the offering price of shares, as the case may be, which the
underwriters have the option to purchase.
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(2)
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Estimated solely for the purpose of
calculating the registration fee pursuant to Rule 457(c) of
the Securities Act of 1933, as amended, based on the average of
the high and low prices of the Registrants Common Stock as
reported on the New York Stock Exchange on June 13, 2008.
The actual amount received by the selling shareholders will be
based upon fluctuating market prices.
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The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
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.
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Subject to Completion. Dated
June 19, 2008.
10,000,000 Shares
CVR Energy,
Inc.
Common Stock
All of the shares of common stock to be sold in this offering
are being sold by the selling stockholders identified in this
prospectus. CVR Energy, Inc. will not receive any of the
proceeds from the sale of shares by the selling stockholders.
Our common stock is listed on the New York Stock Exchange under
the symbol CVI. The last reported sale price of our
common stock on June 18, 2008 was $24.98 per share.
Concurrently with this offering, CVR Energy, Inc. is offering
$125,000,000 aggregate principal amount of
its % Convertible Senior Notes
due 2013 in a registered public offering. The consummation of
this offering is not conditioned upon the concurrent
consummation of the offering of the convertible notes and vice
versa.
See Risk Factors beginning on page 24 to
read about factors you should consider before buying shares of
the common stock.
Neither the Securities and Exchange Commission nor any other
regulatory body has approved or disapproved of these securities
or passed upon the adequacy or accuracy of this prospectus. Any
representation to the contrary is a criminal offense.
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Per Share
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Total
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Public offering price
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$
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$
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Underwriting discount
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$
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$
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Proceeds, before expenses, to the selling stockholders
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$
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$
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To the extent that the underwriters sell more than
10,000,000 shares of common stock, the underwriters have
the option to purchase up to an additional 1,500,000 shares
of common stock from certain of the selling stockholders at the
public offering price less the underwriting discount. CVR Energy
will not receive any of the proceeds from the sale of shares by
certain of the selling stockholders pursuant to any exercise of
the underwriters option to purchase additional
shares.
The underwriters expect to deliver the shares against payment in
New York, New York
on ,
2008.
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Goldman,
Sachs & Co.
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Deutsche Bank
Securities
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Prospectus
dated ,
2008.
PROSPECTUS
SUMMARY
This summary highlights selected information contained
elsewhere in this prospectus. You should carefully read the
entire prospectus, including the Risk Factors and
the consolidated financial statements and related notes included
elsewhere in this prospectus, before making an investment
decision. In this prospectus, all references to the
Company, CVR Energy, we,
us, and our refer to CVR Energy, Inc.
and its consolidated subsidiaries, unless the context otherwise
requires or where otherwise indicated. References in this
prospectus to the nitrogen fertilizer business and
the Partnership refer to CVR Partners, LP, the
entity that owns and operates the nitrogen fertilizer facility.
We currently own all of the interests in CVR Partners, LP (other
than the managing general partner interest and associated
incentive distribution rights, which are held by CVR GP, LLC, or
Fertilizer GP, an entity owned by our controlling stockholders
and certain members of our senior management team). See
The Nitrogen Fertilizer Limited Partnership. You
should also see the Glossary of Selected Terms
beginning on page 282 for definitions of some of the terms
we use to describe our business and industry. We use non-GAAP
measures in this prospectus, including Net income (loss)
adjusted for unrealized gain or loss from Cash Flow Swap. For a
reconciliation of this measure to net income, see footnote 4
under Summary Consolidated Financial
Information.
CVR Energy,
Inc.
We are an independent refiner and marketer of high value
transportation fuels and, through a limited partnership, a
producer of ammonia and urea ammonia nitrate, or UAN,
fertilizers. We are one of only seven petroleum refiners and
marketers located within the mid-continent region (Kansas,
Oklahoma, Missouri, Nebraska and Iowa). The nitrogen fertilizer
business is the only operation in North America that utilizes a
coke gasification process, and at current natural gas and
petroleum coke, or pet coke, prices, the lowest cost producer
and marketer of ammonia and UAN fertilizers in North America.
Our petroleum business includes a 115,000 barrel per day,
or bpd, complex full coking medium-sour crude refinery in
Coffeyville, Kansas. In addition, our supporting businesses
include (1) a crude oil gathering system serving central
Kansas, northern Oklahoma and southwestern Nebraska,
(2) storage and terminal facilities for asphalt and refined
fuels in Phillipsburg, Kansas, (3) a 145,000 bpd
pipeline system that transports crude oil to our refinery and
associated crude oil storage tanks with a capacity of
approximately 1.2 million barrels and (4) a rack
marketing division supplying product through tanker trucks
directly to customers located in close geographic proximity to
Coffeyville and Phillipsburg and to customers at throughput
terminals on Magellan Midstream Partners L.P.s refined
products distribution systems. In addition to rack sales (sales
which are made at terminals into third party tanker trucks), we
make bulk sales (sales through third party pipelines) into the
mid-continent markets via Magellan and into Colorado and other
destinations utilizing the product pipeline networks owned by
Magellan, Enterprise Products Partners L.P. and NuStar Energy
L.P. Our refinery is situated approximately 100 miles from
Cushing, Oklahoma, one of the largest crude oil trading and
storage hubs in the United States, served by numerous pipelines
from locations including the U.S. Gulf Coast and Canada,
providing us with access to virtually any crude oil variety in
the world capable of being transported by pipeline.
The nitrogen fertilizer business consists of a nitrogen
fertilizer manufacturing facility comprised of (1) a 1,225
ton-per-day
ammonia unit, (2) a 2,025
ton-per-day
UAN unit and (3) an 84 million standard cubic foot per
day gasifier complex. The nitrogen fertilizer business is the
only operation in North America that utilizes a coke
gasification process to produce ammonia (based on data provided
by Blue Johnson & Associates). In 2007, approximately
72% of the ammonia produced by the fertilizer plant was further
upgraded to UAN fertilizer (a solution of urea, ammonium nitrate
and water used as a fertilizer). By using pet coke (a coal-like
substance that is produced during the refining process) instead
of natural gas as a primary raw material, at current natural gas
and pet coke prices the nitrogen fertilizer business is the
lowest cost producer and marketer of ammonia and UAN fertilizers
in
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North America. Furthermore, on average during the last four
years, over 75% of the pet coke utilized by the fertilizer plant
was produced and supplied to the fertilizer plant as a
by-product of our refinery. As such, the nitrogen fertilizer
business benefits from high natural gas prices, as fertilizer
prices generally increase with natural gas prices, without a
directly related change in cost (because pet coke rather than
natural gas is used as a primary raw material). During the
second quarter of 2008, we are enjoying unprecedented fertilizer
prices which have contributed favorably to our earnings.
We generated combined net sales of $2.4 billion,
$3.0 billion and $3.0 billion and operating income of
$270.8 million, $281.6 million and $186.6 million
for the fiscal years ended December 31, 2005, 2006 and
2007, respectively. Our petroleum business generated
$2.3 billion, $2.9 billion and $2.8 billion of
our combined net sales, respectively, over these periods, with
the nitrogen fertilizer business generating substantially all of
the remainder. In addition, during these periods, our petroleum
business contributed $199.7 million, $245.6 million
and $144.9 million, respectively, of our combined operating
income with substantially all of the remainder contributed by
the nitrogen fertilizer business. For the three months ended
March 31, 2008, we generated combined net sales of
$1.22 billion and operating income of $87.4 million.
Our petroleum business generated $1.17 billion of our
combined net sales and $63.6 million of our combined
operating income during this period, with substantially all of
the remainder contributed by the nitrogen fertilizer business.
Key Market
Trends
We have identified several key factors which we believe are
influencing the outlook for the refining and nitrogen fertilizer
industries.
For the refining industry, these factors include the following:
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High capital costs, historical excess capacity and environmental
regulatory requirements that have limited the construction of
new refineries in the United States over the past 30 years.
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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.
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Crack spreads are increasing in terms of absolute value with
dramatically higher crude oil costs, but are substantially
narrower as a percentage of crude oil costs, which has reduced
oil refinery profitability.
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A shift in market fundamentals for global petroleum refiners.
The most profitable end products for refiners have shifted from
gasoline products to distillate products.
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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.
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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.
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Limited competitive threat from foreign refiners due to
sophisticated U.S. fuel specifications and increasing
foreign demand for refined products.
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For the nitrogen fertilizer industry, these factors include the
following:
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Nitrogen fertilizer prices in the United States are experiencing
all-time highs. Based on industry projections, including from
Blue Johnson, these high prices are forecast to continue for the
next several years.
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Nitrogen fertilizer prices have been decoupled from their
historical correlation with natural gas prices in recent years,
and increased substantially more than natural gas prices in 2007
and
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2008 (based on data provided by Blue Johnson). Moreover, natural
gas prices are currently higher in the United States and Canada
compared to prevailing prices in the years prior to 2004. High
North American natural gas prices contribute to the currently
high prices for nitrogen-based fertilizers in the United States.
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The Energy Independence and Security Act of 2007 requires fuel
producers to use at least 36 billion gallons of biofuel
(such as ethanol) by 2022, a nearly five-fold increase over
current levels. The increase in grain production necessary to
meet this requirement is expected to result in rising demand for
nitrogen-based fertilizers.
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World population and economic growth, combined with changing
dietary trends in many nations, has significantly increased
demand for U.S. agricultural production and exports.
Increasing U.S. crop production requires higher application
rates of fertilizers, primarily nitrogen-based fertilizers.
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Both of our industries are cyclical and volatile and have
experienced downturns in the past. See Risk Factors.
Our Competitive
Strengths
Regional Advantage and Strategic Asset
Location.
Our refinery is located in the
southern portion of the PADD II
Group 3 distribution area. Because refined product
demand in this area exceeds production, the region has
historically required U.S. Gulf Coast imports to meet
demand. We estimate that this favorable supply/demand imbalance
combined with our lower pipeline transportation cost as compared
to the U.S. Gulf Coast refiners has allowed us to generate
refining margins, as measured by the 2-1-1 crack spread, that
have exceeded U.S. Gulf Coast refining margins by
approximately $2.14 per barrel on average for the last four
years. The 2-1-1 crack spread is a general industry standard
that approximates the per barrel refining margin resulting from
processing two barrels of crude oil to produce one barrel of
gasoline and one barrel of heating oil.
In addition, the nitrogen fertilizer business is geographically
advantaged to supply nitrogen fertilizer products to markets in
Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without
incurring intermediate transfer, storage, barge or pipeline
freight charges. Because the nitrogen fertilizer business does
not incur these costs, this geographic advantage provides it
with a distribution cost advantage over competitors not located
in the farm belt who transport ammonia and UAN from the
U.S. Gulf Coast, based on recent freight rates and pipeline
tariffs for U.S. Gulf Coast importers.
Access to and Ability to Process Multiple Crude
Oils.
Since June 2005 we have significantly
expanded the variety of crude grades processed in any given
month. While our proximity to the Cushing crude oil trading hub
minimizes the likelihood of an interruption to our supply, we
intend to further diversify our sources of crude oil. Among
other initiatives in this regard, we maintain capacity on the
Spearhead pipeline, which connects Chicago to the Cushing hub.
We have also committed to additional pipeline capacity on the
proposed Keystone pipeline project currently under development
by TransCanada Keystone Pipeline, LP which will provide us with
access to incremental oil supplies from Canada. We also own and
operate a crude gathering system serving northern Oklahoma,
central Kansas and southwestern Nebraska, which allows us to
acquire quality crudes at a discount to West Texas intermediate
crude oil, or WTI, which is used as a benchmark for other crude
oils.
High Quality, Modern Refinery with Solid Track
Record.
Our refinerys complexity allows
us to optimize the yields (the percentage of refined product
that is produced from crude and other feedstocks) of higher
value transportation fuels (gasoline and distillate), which
currently account for approximately 94% of our liquid production
output. Complexity is a measure of a refinerys ability to
process lower quality crude in an economic manner; greater
complexity makes a refinery more profitable. From 1995 through
March 31, 2008, we have invested approximately
$725 million to modernize our oil refinery and to meet more
stringent U.S. environmental, health and safety
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requirements. As a result, our refinerys complexity has
increased from 10.0 to 12.1, and we have achieved significant
increases in our refinery crude oil throughput rate, from an
average of less than 90,000 bpd prior to June 2005 to an
average of over 102,000 bpd in the second quarter of 2006,
over 94,500 bpd for all of 2006 and over 110,000 bpd
in the fourth quarter of 2007 with maximum daily rates in excess
of 120,000 bpd for the fourth quarter of 2007.
Unique Coke Gasification Fertilizer
Plant.
The nitrogen fertilizer plant,
completed in 2000, is the newest fertilizer facility in North
America and the only one of its kind in North America using a
pet coke gasification process to produce ammonia. While this
facility is unique to North America, gasification technology has
been in use for over 50 years in various industries to
produce fuel, chemicals and other products from carbon-based
source materials. Because it uses significantly less natural gas
in the manufacture of ammonia than other domestic nitrogen
fertilizer plants, with the currently high price of natural gas
the nitrogen fertilizer business feedstock cost per ton
for ammonia is considerably lower than that of its natural
gas-based fertilizer plant competitors. We estimate that the
facilitys production cost advantage over U.S. Gulf
Coast ammonia producers is sustainable at natural gas prices as
low as $2.50 per MMBtu (at June 16, 2008, the price of
natural gas was $12.93 per MMBtu).
Experienced Management Team.
In
conjunction with the acquisition of our business in June 2005 by
funds affiliated with Goldman, Sachs & Co. and
Kelso & Company, L.P., or the Goldman Sachs Funds and
the Kelso Funds, a new senior management team was formed that
combined selected members of existing management with
experienced new members. Our senior management team averages
over 28 years of refining and fertilizer industry
experience and, in coordination with our broader management
team, has increased our operating income and stockholder value
since June 2005.
Mr. John J. Lipinski, our Chief Executive Officer, has over
36 years of experience in the refining and chemicals
industries, and prior to joining us in connection with the
acquisition of Coffeyville Resources in June 2005, was in charge
of a 550,000 bpd refining system and a multi-plant
fertilizer system. Mr. Stanley A. Riemann, our Chief
Operating Officer, has over 34 years of experience, and
prior to joining us in March 2004, was in charge of one of the
largest fertilizer manufacturing systems in the United States.
Mr. James T. Rens, our Chief Financial Officer, has over
19 years of experience in the energy and fertilizer
industries, and prior to joining us in March 2004, was the chief
financial officer of two fertilizer manufacturing companies.
Our Business
Strategy
The primary business objectives for our refinery business are to
increase value for our stockholders and to maintain our position
as an independent refiner and marketer of refined fuels in our
markets by maximizing the throughput and efficiency of our
petroleum refining assets. In addition, managements
business objectives on behalf of the nitrogen fertilizer
business are to increase value for our stockholders and maximize
the production and efficiency of the nitrogen fertilizer
facilities. We intend to accomplish these objectives through the
following strategies:
Pursuing Organic Expansion
Opportunities.
We continually evaluate
opportunities to expand our existing asset base and consider
capital projects that accentuate our core competitiveness in
petroleum refining. We are also evaluating projects that will
improve our ability to process heavy crude oil feedstocks and to
increase our overall operating flexibility with respect to crude
oil slates. In addition, management also continually evaluates
capital projects that are intended to enhance the
Partnerships competitiveness in nitrogen fertilizer
manufacturing.
Increasing the Profitability of Our Existing
Assets.
We strive to improve our operating
efficiency and to reduce our costs by controlling our cost
structure. We intend to make investments to improve the
efficiency of our operations and pursue cost saving initiatives.
We have recently completed the greenfield construction of a new
continuous catalytic reformer. This project is expected to
increase the profitability of our petroleum business through
increased refined product yields and the
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elimination of scheduled downtime associated with the reformer
that was replaced. In addition, this project reduces the
dependence of our refinery on hydrogen supplied by the
fertilizer facility, thereby allowing the nitrogen fertilizer
business to generate higher margins by using the hydrogen to
produce ammonia and UAN. The nitrogen fertilizer business
expects, over time, to convert 100% of its production to
higher-margin UAN.
Seeking Strategic Acquisitions.
We
intend to consider strategic acquisitions within the energy
industry that are beneficial to our shareholders. We will seek
acquisition opportunities in our existing areas of operation
that have the potential for operational efficiencies. We may
also examine opportunities in the energy industry outside of our
existing areas of operation and in new geographic regions. In
addition, working on behalf of the Partnership, management may
pursue strategic and accretive acquisitions within the
fertilizer industry, including opportunities in different
geographic regions. We have no agreements or understandings with
respect to any acquisitions at the present time.
Pursuing Opportunities to Maximize the Value of the
Nitrogen Fertilizer Business.
Our management,
acting on behalf of the Partnership, will continually evaluate
opportunities that are intended to enable the Partnership to
grow its distributable cash flow. Managements strategies
specifically related to the growth opportunities of the
Partnership include the following:
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Expanding UAN Production.
The nitrogen
fertilizer business is moving forward with an approximately
$120 million nitrogen fertilizer plant expansion, of which
approximately $11 million was incurred as of March 31,
2008. This expansion is expected to permit the nitrogen
fertilizer business to increase its UAN production and to result
in its UAN manufacturing facility consuming substantially all of
its net ammonia production. This should increase the nitrogen
fertilizer plants margins because UAN has historically
been a higher margin product than ammonia. The UAN expansion is
expected to be complete in July 2010 and it is estimated that it
will result in an approximately 50% increase in the nitrogen
fertilizer business annual UAN production. The company has
also begun to acquire or lease offsite UAN storage facilities
and continues to expand this program.
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Executing Several Efficiency-Based and Other
Projects.
The nitrogen fertilizer business is
currently engaged in several efficiency-based and other projects
in order to reduce overall operating costs, incrementally
increase its ammonia production and utilize byproducts to
generate revenue. For example, by redesigning the system that
segregates carbon dioxide, or
CO
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during the gasification process, the nitrogen fertilizer
business estimates that it will be able to produce approximately
25 tons per day of incremental ammonia, worth approximately
$6 million per year at current market prices. The nitrogen
fertilizer business estimates that this project will cost
approximately $7 million (of which none has yet been
incurred) and will be completed in 2010. The nitrogen fertilizer
business has a proven track record of operating gasifiers and is
well positioned to offer operating and technical services as a
third-party operator to other gasifier-based projects.
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Evaluating Construction of a Third Gasifier Unit and a New
Ammonia Unit and UAN Unit at the Nitrogen Fertilizer
Plant
. The nitrogen fertilizer business has
engaged a major engineering firm to help it evaluate the
construction and operation of an additional gasifier unit to
produce a synthesis gas from pet coke. It is expected that the
addition of a third gasifier unit, together with additional
ammonia and UAN units, to the nitrogen fertilizer business
operations could result, on a long-term basis, in an increase in
UAN production of approximately 75,000 tons per month. This
project is in its earliest stages of review and is still subject
to numerous levels of internal analysis.
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Other opportunities our management may consider on behalf of the
Partnership in the event that its managing general partner
proceeds with an initial offering include acquiring certain of
our petroleum business ancillary assets and providing
incremental pipeline transportation and storage infrastructure
services to our petroleum business. There are currently no
agreements or
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understandings in place with respect to any such acquisitions or
opportunities, and there can be no assurance that the
Partnership would be able to operate any of these assets or
businesses profitably.
Nitrogen
Fertilizer Limited Partnership
In conjunction with the closing of our initial public offering
in October 2007, the nitrogen fertilizer business was
transferred to CVR Partners, LP, or the Partnership. The
Partnership has two general partners: a managing general
partner, which is owned by the Goldman Sachs Funds, the Kelso
Funds and our senior management, and a second general partner,
owned by us.
We own all of the interests in the Partnership (other than the
managing general partner interest and associated IDRs described
below) and are currently entitled to all cash distributed by the
Partnership. The managing general partner is not entitled to
participate in Partnership distributions except in respect of
its incentive distribution rights, or IDRs, which entitle it to
receive increasing percentages of the Partnerships
quarterly distributions if the Partnership increases its
distributions above $0.4313 per unit. The Partnership will not
make any distributions with respect to the IDRs until the
aggregate adjusted operating surplus (as defined on
page 234) generated by the Partnership during the period
from October 24, 2007 through December 31, 2009 has
been distributed in respect of the interests which we hold
and/or
the
Partnerships common and subordinated units (none of which
are yet outstanding but which would be issued if the Partnership
consummates an equity offering in the future). In addition,
there will be no distributions paid on the managing general
partners IDRs for so long as the Partnership or its
subsidiaries are guarantors under our credit facilities.
While we are initially entitled to receive all cash that is
distributed by the Partnership, the partnership agreement
provides that, once the Partnership has distributed all
aggregate adjusted operating surplus generated by the
Partnership during the period from October 24, 2007 through
December 31, 2009, the managing general partner will be
entitled to receive distributions on its IDRs only after we have
received a quarterly distribution of $0.4313 per unit (or
$52 million per year in the aggregate, assuming we continue
to own all of the Partnerships interests that we currently
own) from the Partnership. This quarterly distribution amount
does not represent an amount that the Partnership currently
intends to distribute to us, but represents the contractual term
establishing our and the managing general partners
relative right to quarterly distributions from the Partnership,
subject to the other limitations set forth in the partnership
agreement and described herein. This amount may be changed at
the time of the Partnerships initial offering, if any. The
percentage of available cash distributed by the Partnership we
receive will be limited (1) if the Partnership issues
common units in a public or private offering, in which event all
or a portion of our interests in the Partnership will become
subordinated units and the balance, if any, will become common
units, (2) if we sell or are required to sell any of our
special units, and (3) at such time as the managing general
partner begins to receive distributions with respect to its IDRs.
The Partnership is operated by our senior management pursuant to
a services agreement among us, the managing general partner and
the Partnership. We pay all of our senior managements
compensation, and the Partnership reimburses us for the time our
senior management spends working for the Partnership. The
Partnership is managed by the managing general partner and us,
as special general partner. As special general partner of the
Partnership, we have (1) joint management rights regarding
the appointment, termination and compensation of the chief
executive officer and chief financial officer of the managing
general partner, (2) the right to designate two members of
the board of directors of the managing general partner and
(3) joint management rights regarding specified major
business decisions relating to the Partnership.
The Partnership filed a registration statement in
February 2008 for an initial public offering of its common
units. On June 13, 2008, we announced that the managing
general partner of the Partnership has decided to postpone
indefinitely the Partnerships initial public offering due
to current market conditions for master limited partnerships.
The Partnership subsequently requested the registration
statement be withdrawn. We believe maintaining the fertilizer
business within the
6
Company provides greater value for CVR Energy shareholders than
would be the case if the Partnership became a publicly-traded
partnership at this time. The Partnership may elect to move
forward with a public or private offering in the future. Any
future public or private offering by the Partnership would be
made solely at the discretion of the Partnerships managing
general partner, subject to our specified joint management
rights, and would be subject to market conditions and
negotiation of terms acceptable to the Partnerships
managing general partner. In connection with the
Partnerships initial public or private offering, if any,
the Partnership may require us to include a sale of a portion of
our interests in the Partnership. If the Partnership becomes a
public company, we may consider a secondary offering of
interests which we own. We cannot assure you that any such
transaction will be consummated.
For more detailed information about the Partnership, see
The Nitrogen Fertilizer Limited Partnership.
Cash Flow
Swap
In conjunction with the acquisition of our business by
Coffeyville Acquisition LLC, on June 16, 2005, Coffeyville
Acquisition LLC entered into a series of commodity derivative
arrangements, or the Cash Flow Swap, with J. Aron &
Company, or J. Aron, a subsidiary of The Goldman Sachs Group,
Inc., and a related party of ours. The derivative took the form
of three New York Mercantile Exchange, or NYMEX, swap agreements
whereby if crack spreads in absolute terms fall below the fixed
level, J. Aron agreed to pay the difference to us, and if crack
spreads in absolute terms rise above the fixed level, we agreed
to pay the difference to J. Aron. The Cash Flow Swap was
assigned from Coffeyville Acquisition LLC to Coffeyville
Resources, LLC on June 24, 2005.
Based on crude oil capacity of 115,000 bpd, the Cash Flow
Swap represents approximately 58% and 14% of crude oil capacity
for the periods July 1, 2008 through June 30, 2009 and
July 1, 2009 through June 30, 2010, respectively.
Under the terms of our credit facility and upon meeting specific
requirements related to our leverage ratio and our credit
ratings, we are permitted to reduce the Cash Flow Swap to
35,000 bpd, or approximately 30% of expected crude oil
capacity, for the period from April 1, 2008 through
December 31, 2008 and terminate the Cash Flow Swap in 2009
and 2010, so long as at the time of reduction or termination, we
pay the amount of unrealized losses associated with the amount
reduced or terminated.
We entered into the Cash Flow Swap for the following reasons:
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Debt was used as part of the acquisition financing in June 2005
which required the introduction of a financial risk management
tool intended to mitigate a portion of the inherent commodity
price based volatility in our cash flow and preserve our ability
to service debt; and
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|
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.
|
The current environment of high and rising crude oil prices has
led to higher crack spreads in absolute terms but significantly
narrower crack spreads as a percentage of crude oil prices. As a
result, the Cash Flow Swap, under which payments are calculated
based on crack spreads in absolute terms, has had and continues
to have a material negative impact on our earnings. Due to the
Cash Flow Swap, we estimate we will owe J. Aron approximately
$54 million on July 8, 2008 for crude oil we settled
or will settle with respect to the quarter ending June 30,
2008, based on June 16, 2008 pricing. We also owe J. Aron
$123.7 million plus accrued interest ($5.8 million as
of June 1, 2008) on August 31, 2008 under deferral
arrangements we entered into because of the temporary cessation
of our operations on June 30, 2007 due to the flood. For
more information on the Cash Flow Swap, please see Certain
Relationships and Related Party
Transactions Transactions with the Goldman
Sachs Funds and the Kelso Funds J. Aron &
Company and Managements Discussion and
7
Analysis of Financial Condition and Results of
Operations Factors Affecting Comparability of Our
Financial Results J. Aron Deferrals.
We have determined that the Cash Flow Swap does not qualify as a
hedge for hedge accounting purposes under current United States
generally accepted accounting principles, or 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. Given the significant periodic fluctuations in
the amounts of unrealized gains and losses, management utilizes
Net income (loss) adjusted for unrealized gain or loss
from Cash Flow Swap as a key indicator of our business
performance and believes that this non-GAAP measure is a useful
measure for investors in analyzing our business. For a
discussion of the calculation and use of this measure, see
footnote 4 to our Summary Consolidated Financial Information.
Convertible Notes
Offering
Concurrently with this offering of common stock by our selling
stockholders, we are offering $125.0 million aggregate
principal amount
of % Convertible Senior
Notes due 2013, or the convertible notes offering, in a
registered public offering. We intend to use the net proceeds
from the convertible notes offering for general corporate
purposes, which may include using a portion of the proceeds to
pay amounts owed to J. Aron under the Cash Flow Swap and for
future capital investments. We cannot give any assurance that
the convertible senior notes offering will be completed on the
terms set forth in the convertible senior notes offering
registration statement or at all. The consummation of this
offering is not conditioned upon the consummation of the
offering of the convertible senior notes and vice versa.
Recent
Developments
During the second quarter of 2008, we are enjoying unprecedented
fertilizer prices which have contributed favorably to our
earnings. Strong industry fundamentals have led current demand
for nitrogen fertilizers to all time highs. U.S. corn
inventories at the end of the 2008-2009 fertilizer year are
projected to be at 673 million bushels, which is the lowest
level since 1995-1996. Corn prices are at record high levels,
and corn planting for 2008-2009 is projected to be higher than
2007-2008. Nitrogen fertilizer prices are at record high levels
due to increased demand and increasing worldwide natural gas
prices. In addition, nitrogen fertilizer prices, which
historically showed a positive correlation with natural gas
prices, have been decoupled from, and increased substantially
more than, natural gas prices in 2007 and 2008. In addition to
demand driven by biofuel fuel production, the quest for
healthier lives and better diets in developing countries is a
primary driving factor behind the increased global demand for
fertilizers. As of June 16, 2008, our order book for UAN
included 367,825 tons at an average netback price of $326.56 per
ton and 34,898 tons of ammonia at an average netback price of
$620.61 per ton.
At the same time, however, crude oil prices have reached record
levels, and while crack spreads have increased to historically
high absolute values, they are below historical levels as a
percentage of crude oil prices. Because crack spreads as a
percentage of crude oil prices have not kept pace with
increasing crude oil prices, our earnings will be negatively
impacted in the second quarter of 2008. The Cash Flow Swap will
also have a material negative impact on our earnings through at
least June 2009 due to the fact that losses on the Cash Flow
Swap increase as crack spreads in absolute terms increase. In
addition, our second quarter has been negatively impacted by
unplanned downtime at the fertilizer plant and the refinery and
increase in non-cash share-based compensation costs as a result
of our increased stock price.
We have begun negotiations to enter into a new
$25.0 million senior secured term loan, or the proposed
senior secured credit facility, which we anticipate will contain
covenants substantially similar to our existing credit facility.
We have not entered into any agreement regarding this new credit
facility,
8
and there is no guarantee that we will be able to enter into the
proposed senior secured credit facility on the terms described
herein or at all.
Our
History
Prior to March 3, 2004, our refinery assets and the
nitrogen fertilizer plant were operated as a small component of
Farmland Industries, Inc., or Farmland, an agricultural
cooperative. Farmland filed for bankruptcy protection on
May 31, 2002. Coffeyville Resources, LLC, a subsidiary of
Coffeyville Group Holdings, LLC, won the bankruptcy court
auction for Farmlands petroleum business and a nitrogen
fertilizer plant and completed the purchase of these assets on
March 3, 2004. On June 24, 2005, pursuant to a stock
purchase agreement dated May 15, 2005, all of the
subsidiaries of Coffeyville Group Holdings, LLC were acquired by
Coffeyville Acquisition LLC, an entity principally owned by the
Goldman Sachs Funds and the Kelso Funds.
On October 26, 2007, CVR Energy completed its initial
public offering. CVR Energy was formed as a wholly-owned
subsidiary of Coffeyville Acquisition LLC in September 2006 in
order to complete the initial public offering of the businesses
acquired by Coffeyville Acquisition LLC. In October 2007, the
nitrogen fertilizer business was transferred to the Partnership
and the Partnerships managing general partner was sold to
a new entity owned by the Goldman Sachs Funds, the Kelso Funds
and certain members of our senior management team.
Prior to our initial public offering, Coffeyville Acquisition
LLC directly or indirectly owned all of our subsidiaries. We
were formed as a wholly owned subsidiary of Coffeyville
Acquisition LLC in order to complete our initial public offering.
Risks Relating to
Our Business
We face certain risks that could materially affect our business,
results of operations or financial condition. Our petroleum
business is primarily affected by the relationship, or margin,
between refined product prices and the prices for crude oil;
future volatility in refining industry margins may cause
volatility or a decline in our results of operations. The
current high price of oil has led to a narrowing of crack
spreads as a percentage of crude oil prices. As a result,
refining margins have not kept pace with the price of oil, and
have been further negatively impacted by the Cash Flow Swap. In
addition, disruption of our ability to obtain an adequate supply
of crude oil could reduce our liquidity and increase our costs.
In addition, our refinery and nitrogen fertilizer facilities
face operating hazards and interruptions, including unscheduled
maintenance or downtime. The nitrogen fertilizer plant has high
fixed costs, and if natural gas prices fall below a certain
level, our nitrogen fertilizer business may not generate
sufficient revenue to operate profitably. In addition, our
operations involve environmental risks that may require us to
make substantial capital expenditures to remain in compliance or
to remediate current or future contamination that could give
rise to material liabilities. Also, we may not recover all of
the costs we have incurred in connection with the flood and
crude oil discharge that occurred at our refinery on the weekend
of June 30, 2007. For more detailed information about the
flood and crude oil discharge, including insurance reimbursement
information, see Flood and Crude Oil Discharge.
The partnership structure through which we own the nitrogen
fertilizer business also involves numerous risks that could
materially affect our business. The managing general partner of
the Partnership is owned by our controlling stockholders and
senior management and manages the operations of the Partnership
(subject to our specified joint management rights). The managing
general partner owns incentive distribution rights which, over
time, will entitle it to receive increasing percentages of
quarterly distributions from the Partnership if the Partnership
increases its quarterly distributions over a set amount. We are
not entitled to cash distributed in respect of the incentive
distribution rights. If in the future the managing general
partner decides to sell interests in the Partnership, we and
you, as a stockholder of CVR Energy, will no longer have access
to the cash flows of the Partnership to which the purchasers of
these interests will be entitled, and at least 40%
9
(and potentially all) of our interests will be subordinated to
the interests of the new investors. In addition, the managing
general partner of the Partnership has a fiduciary duty to favor
the interests of its owners, and these interests may differ from
our interests and the interests of our stockholders. The members
of our senior management also face conflicts of interest because
they serve as executive officers of both CVR Energy and the
managing general partner of the Partnership.
In May 2008, we restated our consolidated financial statements
for the year ended December 31, 2007 and the related
quarter ended September 30, 2007 as a result of material
weaknesses in our disclosure controls and procedures and
internal control over financial reporting. We are in the process
of remediating these material weaknesses, but there can be no
assurance that we will not in the future identify additional
material weaknesses or significant deficiencies in our
disclosure controls and procedures or internal control over
financial reporting.
For more information about these and other risks relating to our
company, see Risk Factors beginning on page 24
and Cautionary Note Regarding Forward-Looking
Statements beginning on page 62. You should carefully
consider these risk factors together with all other information
included in this prospectus.
10
Organizational
Structure
The following chart illustrates our organizational structure and
the organizational structure of the Partnership upon the
completion of this offering, assuming the underwriters do not
exercise their option to purchase additional shares from certain
of the selling stockholders:
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*
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CVR GP, LLC, which we refer to as
Fertilizer GP, is the managing general partner of CVR Partners,
LP. As managing general partner, Fertilizer GP holds incentive
distribution rights, or IDRs, which entitle it to receive
increasing percentages of the Partnerships quarterly
distributions if the Partnership increases its distributions
above an amount specified in the limited partnership agreement.
The IDRs will only be payable after the Partnership has
distributed all aggregated adjusted operating surplus generated
by the Partnership during the period from October 24, 2007
through December 31, 2009.
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11
The
Offering
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Shares of common stock offered by the selling stockholders
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10,000,000 shares.
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Option to purchase additional shares of common stock from
certain of the selling stockholders
|
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1,500,000 shares.
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Common stock outstanding immediately after the offering
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86,141,291 shares.
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Use of proceeds
|
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We will not receive any proceeds from sales of our common stock
by the selling stockholders in this offering.
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Dividend policy
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We do not anticipate paying any dividends on our common stock in
the foreseeable future.
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New York Stock Exchange symbol
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CVI
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Concurrent notes offering
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Concurrently with this offering, we are offering $125,000,000
aggregate principal amount
of % Convertible Senior Notes
due 2013 in a registered public offering. The consummation of
this offering is not conditioned upon the concurrent
consummation of the convertible notes offering and vice versa.
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Risk Factors
|
|
See Risk Factors beginning on page 24 of this
prospectus for a discussion of factors that you should carefully
consider before deciding to invest in shares of our common stock.
|
The number of shares of common stock outstanding immediately
after the offering excludes 7,500,000 shares of common
stock issuable under our long-term incentive plan. Of this
amount, options to purchase 23,250 shares of common stock
have been issued at a weighted average exercise price of $22.23,
and 17,500 shares of non-vested restricted stock have been
awarded.
CVR Energy, Inc. was incorporated in Delaware in September 2006.
Our principal executive offices are located at 2277 Plaza Drive,
Suite 500 Sugar Land, Texas 77479, and our telephone number
is
(281) 207-3200.
Our website address is www.cvrenergy.com. Information contained
in or linked to or from our website is not a part of this
prospectus.
Prior to this offering, Coffeyville Acquisition, an entity owned
principally by the Kelso Funds, and Coffeyville
Acquisition II, an entity owned principally by the Goldman
Sachs Funds, together beneficially owned approximately 73.0% of
our capital stock. Coffeyville Acquisition and Coffeyville
Acquisition II are, along with our chairman and chief
executive officer, selling all of the shares of common stock
being sold in this offering. Certain members of our senior
management team will receive proceeds from the sale of common
stock by Coffeyville Acquisition and Coffeyville
Acquisition II as a result of their membership interest in
these entities. Payments will also be made to certain members of
our senior management team pursuant to the Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan I) and
the Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan II) as a direct result of the sale of shares of our
common stock by Coffeyville Acquisition and Coffeyville
Acquisition II. For further information, see Principal and
Selling Stockholders, Certain Relationships and
Related Party Transactions and The Nitrogen
Fertilizer Limited Partnership.
Depending on market conditions at the time of pricing of this
offering and other considerations, the selling stockholders may
sell fewer or more shares than the number set forth on the cover
page of this prospectus.
12
Summary
Consolidated Financial Information
The summary consolidated financial information presented below
under the caption Statement of Operations Data for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005 and the years ended
December 31, 2006 and 2007, and the summary consolidated
financial information presented below under the caption Balance
Sheet Data as of December 31, 2006 and 2007, has been
derived from our consolidated financial statements included
elsewhere in this prospectus, which consolidated financial
statements have been audited by KPMG LLP, independent registered
public accounting firm. The summary consolidated balance sheet
data as of December 31, 2005 is derived from our audited
consolidated financial statements that are not included in this
prospectus. The summary unaudited interim consolidated financial
information presented below under the caption Statement of
Operations Data for the three-month period ended March 31,
2007 and the three-month period ended March 31, 2008, and
the summary consolidated financial information presented below
under the caption Balance Sheet Data as of March 31, 2008,
have been derived from our unaudited interim consolidated
financial statements, which are included elsewhere in this
prospectus and have been prepared on the same basis as the
audited consolidated financial statements. In the opinion of
management, the interim data reflect all adjustments, consisting
only of normal and recurring adjustments, necessary for a fair
presentation of results for these periods. Operating results for
the three-month period ended March 31, 2008 are not
necessarily indicative of the results that may be expected for
the year ending December 31, 2008.
We calculate earnings per share for the years ended
December 31, 2006 and 2007 and the three-month period ended
March 31, 2007 on a pro forma basis, assuming our post-IPO
capital structure had been in place for the entire year for each
of 2006 and 2007. For the year ended December 31, 2007,
17,500 non-vested common shares and 18,900 common stock options
have been excluded from the calculation of pro forma diluted
earnings per share because the inclusion of such common stock
equivalents in the number of weighted average shares outstanding
would be anti-dilutive. We have omitted earnings per share data
for 2005 because we operated under a different capital structure
than our current capital structure and, therefore, the
information is not meaningful.
On June 24, 2005, pursuant to a stock purchase agreement
dated May 15, 2005, Coffeyville Acquisition LLC acquired
all of the subsidiaries of Coffeyville Group Holdings, LLC. See
note 1 to our consolidated financial statements included
elsewhere in this prospectus. As a result of certain adjustments
made in connection with this acquisition, a new basis of
accounting was established on the date of the acquisition. Since
the assets and liabilities of Successor and Immediate
Predecessor were each presented on a new basis of accounting,
the financial information for periods before and after
June 24, 2005 is not comparable.
On April 23, 2008, the audit committee of our board of
directors and management concluded that our previously issued
consolidated financial statements for the year ended
December 31, 2007 and the related quarter ended
September 30, 2007 contained errors. See footnote 2 to
our consolidated financial statements for the year ended
December 31, 2007 included elsewhere in this prospectus and
Managements Discussion and Analysis of Financial
Condition and Results of Operations Restatement of
Year Ended December 31, 2007 and Quarter Ended September
30, 2007 Financial Statements. All information presented
in this prospectus reflects our restated financial results.
Financial data for the 2005 fiscal year is presented as the
174 days ended June 23, 2005 and the 233 days
ended December 31, 2005. Coffeyville Acquisition, LLC had
no financial statement activity during the period from
May 13, 2005 to June 24, 2005, with the exception of
certain crude oil, heating oil, and gasoline option agreements
entered into with a related party as of May 16, 2005.
13
The historical data presented below has been derived from
financial statements that have been prepared using GAAP included
elsewhere in this prospectus. This data should be read in
conjunction with, and is qualified in its entirety by reference
to, the financial statements and related notes and
Managements Discussion and Analysis of Financial
Condition and Results of Operations included elsewhere in
this prospectus.
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Successor
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Three Months
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Three Months
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Ended
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Ended
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March 31
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March 31
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2007
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2008
|
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(unaudited, in millions, except share and per share data)
|
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|
Statement of Operations Data:
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|
|
|
|
|
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|
Net sales
|
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$
|
390.5
|
|
|
$
|
1,223.0
|
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Cost of product sold (exclusive of depreciation and amortization)
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303.7
|
|
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|
1,036.2
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|
Direct operating expenses (exclusive of depreciation and
amortization)
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113.4
|
|
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60.6
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
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13.2
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|
|
13.4
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Net costs associated with flood(1)
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|
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5.8
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Depreciation and amortization(2)
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14.2
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|
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19.6
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|
|
|
|
|
|
|
|
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Operating income (loss)
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(54.0
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)
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$
|
87.4
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Other income, net
|
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0.5
|
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0.9
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Interest expense and other financing costs
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(11.9
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)
|
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(11.3
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)
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Loss on derivatives, net
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(137.0
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)
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(47.9
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)
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|
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|
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Income (loss) before income taxes and minority interest in
subsidiaries
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$
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(202.4
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)
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$
|
29.1
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Income tax (expense) benefit
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47.3
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(6.9
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)
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Minority interest in (income) loss of subsidiaries
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0.7
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|
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|
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Net income (loss)(3)
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$
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(154.4
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)
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$
|
22.2
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Pro forma loss per share, basic
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$
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(1.79
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)
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Pro forma loss per share, diluted
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$
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(1.79
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)
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|
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Pro forma weighted average shares, basic
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86,141,291
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Pro forma weighted average shares, diluted
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86,141,291
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Earnings per share, basic
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$
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0.26
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Earnings per share, diluted
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$
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0.26
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Weighted average shares, basic
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|
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86,141,291
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Weighted average shares, diluted
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|
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86,158,791
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Segment Financial Data:
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Operating income (loss):
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|
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Petroleum
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(63.5
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)
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63.6
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Nitrogen Fertilizer
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9.3
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|
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26.0
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Other
|
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0.2
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|
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(2.2
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)
|
|
|
|
|
|
|
|
|
|
Operating income (loss):
|
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$
|
(54.0
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)
|
|
$
|
87.4
|
|
|
|
|
|
|
|
|
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Depreciation and amortization
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|
|
|
|
|
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Petroleum
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9.8
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|
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14.9
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Nitrogen Fertilizer
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4.4
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4.5
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Other
|
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|
|
|
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0.2
|
|
|
|
|
|
|
|
|
|
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Depreciation and amortization(2)
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$
|
14.2
|
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$
|
19.6
|
|
|
|
|
|
|
|
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Other Financial Data:
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|
|
|
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Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(4)
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$
|
(82.4
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)
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$
|
30.6
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Cash flows provided by operating activities
|
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44.1
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|
|
|
24.2
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Cash flows used in investing activities
|
|
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(107.4
|
)
|
|
|
(26.2
|
)
|
Cash flows provided by (used in) financing activities
|
|
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29.0
|
|
|
|
(3.4
|
)
|
Capital expenditures for property, plant and equipment
|
|
|
107.4
|
|
|
|
26.2
|
|
14
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2007
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
Production (barrels per day)(5)
|
|
|
53,689
|
|
|
|
125,614
|
|
Crude oil throughput (barrels per day)(5)
|
|
|
47,267
|
|
|
|
106,530
|
|
Refining margin per crude oil throughput barrel (dollars)(6)
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
NYMEX 2-1-1 crack spread (dollars)(7)
|
|
$
|
12.17
|
|
|
$
|
11.81
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)(8)
|
|
$
|
22.73
|
|
|
$
|
4.16
|
|
Gross profit (loss) per crude oil throughput per barrel
(dollars)(8)
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)
|
|
|
86.2
|
|
|
|
83.7
|
|
UAN (tons in thousands)
|
|
|
165.7
|
|
|
|
150.1
|
|
On-stream factors:
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
91.8
|
%
|
|
|
91.8
|
%
|
Ammonia
|
|
|
86.3
|
%
|
|
|
90.7
|
%
|
UAN
|
|
|
89.4
|
%
|
|
|
85.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23
|
|
|
|
December 31
|
|
|
December 31
|
|
|
December 31
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
(in millions, except share and per share data)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
980.7
|
|
|
|
$
|
1,454.3
|
|
|
$
|
3,037.6
|
|
|
$
|
2,966.9
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
768.0
|
|
|
|
|
1,168.1
|
|
|
|
2,443.4
|
|
|
|
2,308.8
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
80.9
|
|
|
|
|
85.3
|
|
|
|
199.0
|
|
|
|
276.1
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
18.4
|
|
|
|
|
18.4
|
|
|
|
62.6
|
|
|
|
93.1
|
|
Net costs associated with flood(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41.5
|
|
Depreciation and amortization(2)
|
|
|
1.1
|
|
|
|
|
24.0
|
|
|
|
51.0
|
|
|
|
60.8
|
|
Operating income
|
|
$
|
112.3
|
|
|
|
$
|
158.5
|
|
|
$
|
281.6
|
|
|
$
|
186.6
|
|
Other income (expense)(9)
|
|
|
(8.4
|
)
|
|
|
|
0.4
|
|
|
|
(20.8
|
)
|
|
|
0.2
|
|
Interest expense and other financing costs
|
|
|
(7.8
|
)
|
|
|
|
(25.0
|
)
|
|
|
(43.9
|
)
|
|
|
(61.1
|
)
|
Gain (loss) on derivatives
|
|
|
(7.6
|
)
|
|
|
|
(316.1
|
)
|
|
|
94.5
|
|
|
|
(282.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
$
|
88.5
|
|
|
|
$
|
(182.2
|
)
|
|
$
|
311.4
|
|
|
$
|
(156.3
|
)
|
Income tax (expense) benefit
|
|
|
(36.1
|
)
|
|
|
|
63.0
|
|
|
|
(119.8
|
)
|
|
|
88.5
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(3)
|
|
$
|
52.4
|
|
|
|
$
|
(119.2
|
)
|
|
$
|
191.6
|
|
|
$
|
(67.6
|
)
|
Pro forma earnings per share, basic
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Pro forma earnings per share, diluted
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Pro forma weighted average shares, basic
|
|
|
|
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Pro forma weighted average shares, diluted
|
|
|
|
|
|
|
|
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23
|
|
|
|
December 31
|
|
|
December 31
|
|
|
December 31
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
(in millions, except share and per share data)
|
|
Segment Financial Data
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
|
76.7
|
|
|
|
|
123.0
|
|
|
|
245.6
|
|
|
|
144.9
|
|
Nitrogen Fertilizer
|
|
|
35.3
|
|
|
|
|
35.7
|
|
|
|
36.8
|
|
|
|
46.6
|
|
Other
|
|
|
0.3
|
|
|
|
|
(0.2
|
)
|
|
|
(0.8
|
)
|
|
|
(4.9
|
)
|
Operating income
|
|
|
112.3
|
|
|
|
|
158.5
|
|
|
|
281.6
|
|
|
|
186.6
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
|
0.8
|
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
Nitrogen Fertilizer
|
|
|
0.3
|
|
|
|
|
8.4
|
|
|
|
17.1
|
|
|
|
16.8
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
0.9
|
|
|
|
1.0
|
|
Depreciation and amortization(2)
|
|
|
1.1
|
|
|
|
|
24.0
|
|
|
|
51.0
|
|
|
|
60.8
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(4)
|
|
|
52.4
|
|
|
|
|
23.6
|
|
|
|
115.4
|
|
|
|
(5.6
|
)
|
Cash flows provided by operating activities
|
|
|
12.7
|
|
|
|
|
82.5
|
|
|
|
186.6
|
|
|
|
145.9
|
|
Cash flows (used in) investing activities
|
|
|
(12.3
|
)
|
|
|
|
(730.3
|
)
|
|
|
(240.2
|
)
|
|
|
(268.6
|
)
|
Cash flows provided by (used in) financing activities
|
|
|
(52.4
|
)
|
|
|
|
712.5
|
|
|
|
30.8
|
|
|
|
111.3
|
|
Capital expenditures for property, plant and equipment
|
|
|
12.3
|
|
|
|
|
45.2
|
|
|
|
240.2
|
|
|
|
268.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23
|
|
|
|
December 31
|
|
|
December 31
|
|
|
December 31
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
(unaudited)
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (barrels per day)(5)(10)
|
|
|
99,171
|
|
|
|
|
107,177
|
|
|
|
108,031
|
|
|
|
86,201
|
|
Crude oil throughput (barrels per day)(5)(10)
|
|
|
88,012
|
|
|
|
|
93,908
|
|
|
|
94,524
|
|
|
|
76,285
|
|
Refining margin per crude oil throughput barrel (dollars)(6)
|
|
$
|
9.28
|
|
|
|
$
|
11.55
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
NYMEX 2-1-1 crack spread (dollars)(7)
|
|
|
9.60
|
|
|
|
|
13.47
|
|
|
|
10.84
|
|
|
|
13.95
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)(8)
|
|
|
3.44
|
|
|
|
|
3.13
|
|
|
|
3.92
|
|
|
|
7.52
|
|
Gross profit (loss) per crude oil throughput barrel (dollars)(8)
|
|
|
5.79
|
|
|
|
|
7.55
|
|
|
|
8.39
|
|
|
|
7.79
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)(10)
|
|
|
193.2
|
|
|
|
|
220.0
|
|
|
|
369.3
|
|
|
|
326.7
|
|
UAN (tons in thousands)(10)
|
|
|
309.9
|
|
|
|
|
353.4
|
|
|
|
633.1
|
|
|
|
576.9
|
|
On-stream factors(11):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasifier
|
|
|
97.4
|
%
|
|
|
|
98.7
|
%
|
|
|
92.5
|
%
|
|
|
90.0
|
%
|
Ammonia
|
|
|
95.0
|
%
|
|
|
|
98.3
|
%
|
|
|
89.3
|
%
|
|
|
87.7
|
%
|
UAN
|
|
|
93.9
|
%
|
|
|
|
94.8
|
%
|
|
|
88.9
|
%
|
|
|
78.7
|
%
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
December 31
|
|
|
December 31
|
|
|
December 31
|
|
|
|
March 31
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
64.7
|
|
|
$
|
41.9
|
|
|
$
|
30.5
|
|
|
|
$
|
25.2
|
|
Working capital
|
|
|
108.0
|
|
|
|
112.3
|
|
|
|
10.7
|
|
|
|
|
21.5
|
|
Total assets
|
|
|
1,221.5
|
|
|
|
1,449.5
|
|
|
|
1,868.4
|
|
|
|
|
1,923.6
|
|
Total debt, including current portion
|
|
|
499.4
|
|
|
|
775.0
|
|
|
|
500.8
|
|
|
|
|
499.2
|
|
Minority interest in subsidiaries(12)
|
|
|
|
|
|
|
4.3
|
|
|
|
10.6
|
|
|
|
|
10.6
|
|
Divisional/members/stockholders equity
|
|
|
115.8
|
|
|
|
76.4
|
|
|
|
432.7
|
|
|
|
|
455.1
|
|
|
|
|
(1)
|
|
Represents the write-off of
approximate net costs associated with flood and crude oil spill
that are not probable of recovery. See Flood and Crude Oil
Discharge.
|
|
(2)
|
|
Depreciation and amortization is
comprised of the following components as excluded from cost of
product sold, direct operating expenses and selling, general and
administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
Three
|
|
Three
|
|
|
174 Days
|
|
|
233 Days
|
|
Year
|
|
Year
|
|
|
Months
|
|
Months
|
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
|
June 23
|
|
|
December 31
|
|
December 31
|
|
December 31
|
|
|
March 31
|
|
March 31
|
|
|
2005
|
|
|
2005
|
|
2006
|
|
2007
|
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
|
(in millions)
|
Depreciation and amortization excluded from cost of product sold
|
|
$
|
0.1
|
|
|
|
$
|
1.1
|
|
|
$
|
2.2
|
|
|
$
|
2.4
|
|
|
|
$
|
0.6
|
|
|
$
|
0.6
|
|
Depreciation and amortization excluded from direct operating
expenses
|
|
|
0.9
|
|
|
|
|
22.7
|
|
|
|
47.7
|
|
|
|
57.4
|
|
|
|
|
13.5
|
|
|
|
18.7
|
|
Depreciation and amortization excluded from selling, general and
administrative expenses
|
|
|
0.1
|
|
|
|
|
0.2
|
|
|
|
1.1
|
|
|
|
1.0
|
|
|
|
|
0.1
|
|
|
|
0.3
|
|
Depreciation included in net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
1.1
|
|
|
|
$
|
24.0
|
|
|
$
|
51.0
|
|
|
$
|
68.4
|
|
|
|
$
|
14.2
|
|
|
$
|
19.6
|
|
17
|
|
|
(3)
|
|
The following are certain charges
and costs incurred in each of the relevant periods that are
meaningful to understanding our net income and in evaluating our
performance due to their unusual or infrequent nature:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
Three
|
|
|
174 Days
|
|
|
233 Days
|
|
Year
|
|
Year
|
|
|
Months
|
|
Months
|
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
|
June 23
|
|
|
December 31
|
|
December 31
|
|
December 31
|
|
|
March 31
|
|
March 31
|
|
|
2005
|
|
|
2005
|
|
2006
|
|
2007
|
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
(in millions)
|
|
|
(unaudited)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on extinguishment of debt(a)
|
|
$
|
8.1
|
|
|
|
$
|
|
|
|
$
|
23.4
|
|
|
$
|
1.3
|
|
|
|
$
|
|
|
|
$
|
|
|
Inventory fair market value adjustment(b)
|
|
|
|
|
|
|
|
16.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded letter of credit expense and interest rate swap not
included in interest expense(c)
|
|
|
|
|
|
|
|
2.3
|
|
|
|
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
0.9
|
|
Major scheduled turnaround expense(d)
|
|
|
|
|
|
|
|
|
|
|
|
6.6
|
|
|
|
76.4
|
|
|
|
|
66.0
|
|
|
|
|
|
Loss on termination of swap(e)
|
|
|
|
|
|
|
|
25.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss from Cash Flow Swap
|
|
|
|
|
|
|
|
235.9
|
|
|
|
(126.8
|
)
|
|
|
103.2
|
|
|
|
|
119.7
|
|
|
|
13.9
|
|
|
|
|
(a)
|
|
Represents the write-off of: (i)
$8.1 million of deferred financing costs in connection with
the refinancing of our senior secured credit facility on
June 23, 2005, (ii) $23.4 million in connection with
the refinancing of our senior secured credit facility on
December 28, 2006 and (iii) $1.3 million in connection
with the repayment and termination of three credit facilities on
October 26, 2007.
|
|
(b)
|
|
Consists of the additional cost of
product sold expense due to the step up to estimated fair value
of certain inventories on hand at June 24, 2005 as a result
of the allocation of the purchase price of the Subsequent
Acquisition to inventory.
|
|
(c)
|
|
Consists of fees which are expensed
to selling, general and administrative expenses in connection
with the funded letter of credit facility of $150.0 million
issued in support of the Cash Flow Swap. We consider these fees
to be equivalent to interest expense and the fees are treated as
such in the calculation of EBITDA in the credit facility.
|
|
(d)
|
|
Represents expenses associated with
a major scheduled turnaround at the nitrogen fertilizer plant
and the refinery.
|
|
(e)
|
|
Represents the expense associated
with the expiration of the crude oil, heating oil and gasoline
option agreements entered into by Coffeyville Acquisition LLC in
May 2005.
|
|
|
|
(4)
|
|
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap results from
adjusting for the unrealized portion of the derivative
transaction that was executed in conjunction with the
acquisition of Coffeyville Group Holdings, LLC by Coffeyville
Acquisition LLC on June 24, 2005. On June 16, 2005,
Coffeyville Acquisition LLC entered into the Cash Flow Swap with
J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a
related party of ours. The Cash Flow Swap was subsequently
assigned from Coffeyville Acquisition LLC to Coffeyville
Resources, LLC on June 24, 2005. The derivative took the
form of three NYMEX swap agreements whereby if absolute (i.e.,
in dollar terms, not as a percentage of crude oil prices) crack
spreads fall below the fixed level, J. Aron agreed to pay the
difference to us, and if absolute crack spreads rise above the
fixed level, we agreed to pay the difference to J. Aron. Based
upon expected crude oil capacity of 115,000 bpd, the Cash
Flow Swap represents approximately 58% and 14% of crude oil
capacity for the periods July 1, 2008 through June 30,
2009 and July 1, 2009 through June 30, 2010,
respectively. Under the terms of our credit facility and upon
meeting specific requirements related to our leverage ratio and
our credit ratings, we are permitted to reduce the Cash Flow
Swap to 35,000 bpd, or approximately 30% of expected crude
oil capacity, for the period from April 1, 2008 through
|
18
|
|
|
|
|
December 31, 2008 and
terminate the Cash Flow Swap in 2009 and 2010, so long as at the
time of reduction or termination, we pay the amount of
unrealized losses associated with the amount reduced or
terminated.
|
|
|
|
We have determined that the Cash
Flow Swap does not qualify as a hedge for hedge accounting
purposes under current GAAP. As a result, our periodic
statements of operations reflect in each period material amounts
of unrealized gains and losses based on the increases or
decreases in market value of the unsettled position under the
swap agreements, which is accounted for as a liability on our
balance sheet. As the absolute crack spreads increase we are
required to record an increase in this liability account with a
corresponding expense entry to be made to our statement of
operations. Conversely, as absolute crack spreads decline we are
required to record a decrease in the swap related liability and
post a corresponding income entry to our statement of
operations. Because of this inverse relationship between the
economic outlook for our underlying business (as represented by
crack spread levels) and the income impact of the unrecognized
gains and losses, and given the significant periodic
fluctuations in the amounts of unrealized gains and losses,
management utilizes Net income (loss) adjusted for unrealized
gain or loss from Cash Flow Swap as a key indicator of our
business performance. In managing our business and assessing its
growth and profitability from a strategic and financial planning
perspective, management and our board of directors considers our
GAAP net income results as well as Net income (loss) adjusted
for unrealized gain or loss from Cash Flow Swap. We believe that
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap enhances the understanding of our results of
operations by highlighting income attributable to our ongoing
operating performance exclusive of charges and income resulting
from mark to market adjustments that are not necessarily
indicative of the performance of our underlying business and our
industry. The adjustment has been made for the unrealized loss
from Cash Flow Swap net of its related tax benefit.
|
|
|
|
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap is not a recognized
term under GAAP and should not be substituted for net income as
a measure of our performance but instead should be utilized as a
supplemental measure of financial performance or liquidity in
evaluating our business. Because Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap excludes mark to
market adjustments, the measure does not reflect the fair market
value of our Cash Flow Swap in our net income. As a result, the
measure does not include potential cash payments that may be
required to be made on the Cash Flow Swap in the future. Also,
our presentation of this non-GAAP measure may not be comparable
to similarly titled measures of other companies.
|
|
|
|
The following is a reconciliation
of Net income (loss) adjusted for unrealized gain or loss from
Cash Flow Swap to Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
Three
|
|
|
174 Days
|
|
|
233 Days
|
|
Year
|
|
Year
|
|
|
Months
|
|
Months
|
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
|
June 23
|
|
|
December 31
|
|
December 31
|
|
December 31
|
|
|
March 31
|
|
March 31
|
|
|
2005
|
|
|
2005
|
|
2006
|
|
2007
|
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) adjusted for unrealized gain (loss) from Cash
Flow Swap
|
|
$
|
52.4
|
|
|
|
$
|
23.6
|
|
|
$
|
115.4
|
|
|
$
|
(5.6
|
)
|
|
|
$
|
(82.4
|
)
|
|
$
|
30.6
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit
|
|
|
|
|
|
|
|
(142.8
|
)
|
|
|
76.2
|
|
|
|
(62.0
|
)
|
|
|
|
(72.0
|
)
|
|
|
(8.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
52.4
|
|
|
|
$
|
(119.2
|
)
|
|
$
|
191.6
|
|
|
$
|
(67.6
|
)
|
|
|
$
|
(154.4
|
)
|
|
$
|
22.2
|
|
|
|
|
(5)
|
|
Barrels per day is calculated by
dividing the volume in the period by the number of calendar days
in the period. Barrels per day as shown here is impacted by
plant down-time and other plant disruptions and does not
represent the capacity of the facilitys continuous
operations.
|
|
(6)
|
|
Refining margin per crude oil
throughput barrel is a measurement calculated as the difference
between net sales and cost of product sold (exclusive of
depreciation and amortization) divided by the refinerys
crude oil throughput volumes for the respective periods
presented. Refining margin per crude oil throughput barrel is a
non-GAAP measure that should not be substituted for gross profit
or operating income and that we believe is important to
investors in evaluating our refinerys performance as a
general indication of the amount above our cost of product sold
that we are able to sell refined products. Our calculation of
refining margin per crude oil throughput barrel may differ from
similar calculations of other companies in our industry, thereby
limiting its usefulness as a comparative measure. We
|
19
|
|
|
|
|
use refining margin per crude oil
throughput barrel as the most direct and comparable metric to a
crack spread which is an observable market indication of
industry profitability.
|
|
(7)
|
|
This information is industry data
and is not derived from our audited financial statements or
unaudited interim financial statements.
|
|
(8)
|
|
Direct operating expenses
(exclusive of depreciation and amortization) per crude oil
throughput barrel is calculated by dividing direct operating
expenses (exclusive of depreciation and amortization) by total
crude oil throughput volumes for the respective periods
presented. Direct operating expenses (exclusive of depreciation
and amortization) per crude oil throughput barrel includes costs
associated with the actual operations of the refinery, such as
energy and utility costs, catalyst and chemical costs, repairs
and maintenance and labor and environmental compliance costs but
does not include depreciation or amortization. We use direct
operating expenses (exclusive of depreciation and amortization)
per crude oil throughput barrel as a measure of operating
efficiency within the plant and as a control metric for
expenditures.
|
|
|
|
Direct operating expenses
(exclusive of depreciation and amortization) per crude oil
throughput barrel is a non-GAAP measure. Our calculations of
direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel may differ from
similar calculations of other companies in our industry, thereby
limiting its usefulness as a comparative measure. The following
table reflects direct operating expenses (exclusive of
depreciation and amortization) and the related calculation of
direct operating expenses per crude oil throughput barrel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
Three
|
|
|
174 Days
|
|
|
233 Days
|
|
Year
|
|
Year
|
|
|
Months
|
|
Months
|
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
Ended
|
|
Ended
|
|
|
June 23,
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
|
March 31,
|
|
March 31,
|
|
|
2005
|
|
|
2005
|
|
2006
|
|
2007
|
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
(in millions, except as otherwise indicated)
|
|
|
(unaudited)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Sales
|
|
$
|
903.8
|
|
|
|
$
|
1,363.4
|
|
|
$
|
2,880.4
|
|
|
$
|
2,806.2
|
|
|
|
$
|
352.5
|
|
|
$
|
1,168.5
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
761.7
|
|
|
|
|
1,156.2
|
|
|
|
2,422.7
|
|
|
|
2,300.2
|
|
|
|
|
298.5
|
|
|
|
1,035.1
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
52.6
|
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
|
5.5
|
|
Depreciation and amortization
|
|
|
0.8
|
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit (loss)
|
|
$
|
88.7
|
|
|
|
$
|
135.4
|
|
|
$
|
289.4
|
|
|
$
|
216.8
|
|
|
|
$
|
(52.5
|
)
|
|
$
|
72.7
|
|
Plus direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
52.6
|
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Plus net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
|
5.5
|
|
Plus depreciation and amortization
|
|
|
0.8
|
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin
|
|
$
|
142.1
|
|
|
|
$
|
207.2
|
|
|
$
|
457.7
|
|
|
$
|
506.0
|
|
|
|
$
|
54.0
|
|
|
$
|
133.4
|
|
Refining margin per crude oil throughput barrel (dollars)
|
|
$
|
9.28
|
|
|
|
$
|
11.55
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
Gross profit (loss) per crude oil throughput barrel (dollars)
|
|
$
|
5.79
|
|
|
|
$
|
7.55
|
|
|
$
|
8.39
|
|
|
$
|
7.79
|
|
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)
|
|
$
|
3.44
|
|
|
|
$
|
3.13
|
|
|
$
|
3.92
|
|
|
$
|
7.52
|
|
|
|
$
|
22.73
|
|
|
$
|
4.16
|
|
Operating income (loss)
|
|
|
76.7
|
|
|
|
|
123.0
|
|
|
|
245.6
|
|
|
|
144.9
|
|
|
|
|
(63.5
|
)
|
|
|
63.6
|
|
|
|
|
(9)
|
|
During the 174 days ended
June 23, 2005, the year ended December 31, 2006 and
the year ended December 31, 2007, we recognized a loss of
$8.1 million, $23.4 million and $1.3 million,
respectively, on early extinguishment of debt.
|
20
|
|
|
(10)
|
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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.
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(11)
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On-stream factor is the total
number of hours operated divided by the total number of hours in
the reporting period. Excluding the impact of turnaround at the
nitrogen fertilizer facility in the third quarter of 2006, the
on-stream factors for the year ended December 31, 2006
would have been 97.1% for gasifier, 94.3% for ammonia and 93.6%
for UAN. Excluding the impact of the flood during the weekend of
June 30, 2007, the on-stream factors for the year ended
December 31, 2007 would have been 94.6% for gasifier, 92.4%
for ammonia and 83.9% for UAN.
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(12)
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Minority interest at
December 31, 2006 reflects common stock in two of our
subsidiaries owned by John J. Lipinski (which were exchanged for
shares of our common stock with an equivalent value prior to the
consummation of our initial public offering). Minority interest
at December 31, 2007 and March 31, 2008 reflects
Coffeyville Acquisition III LLCs ownership of the
managing general partner interest and IDRs of the Partnership.
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21
About This
Prospectus
Certain
Definitions
In this prospectus,
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Original Predecessor refers to the former Petroleum Division and
one facility within the eight-plant Nitrogen Fertilizer
Manufacturing and Marketing Division of Farmland which
Coffeyville Resources, LLC acquired on March 3, 2004 in a
sales process under Chapter 11 of the U.S. Bankruptcy
Code;
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Initial Acquisition refers to the acquisition of Original
Predecessor on March 3, 2004 by Coffeyville Resources, LLC;
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Immediate Predecessor refers to Coffeyville Group Holdings, LLC
and its subsidiaries, including Coffeyville Resources, LLC;
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Subsequent Acquisition refers to the acquisition of Immediate
Predecessor on June 24, 2005 by Coffeyville Acquisition
LLC; and
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Successor refers to (1) Coffeyville Acquisition LLC and its
consolidated subsidiaries from June 24, 2005 through
October 15, 2007 and (2) CVR Energy, Inc. and its
consolidated subsidiaries (including the Partnership) on and
after October 16, 2007.
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In addition, in this prospectus:
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Managing general partner refers to CVR GP, LLC, the
Partnerships managing general partner, which is owned by
Coffeyville Acquisition III;
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Special general partner refers to CVR Special GP, LLC, the
Partnerships special general partner, which is indirectly
owned by us;
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General Partners refers to the Partnerships managing
general partner and special general partner;
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Coffeyville Resources refers to Coffeyville Resources, LLC, the
subsidiary of CVR Energy which is the sole limited partner of
the Partnership;
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Coffeyville Acquisition refers to Coffeyville Acquisition LLC,
an entity owned principally by the Kelso Funds, which owns 36.5%
of our common stock prior to this offering and will own 30.7% of
our common stock following this offering, assuming all of the
shares of common stock offered hereby are sold and the
underwriters do not exercise their option to purchase additional
shares;
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Coffeyville Acquisition II refers to Coffeyville
Acquisition II LLC, an entity owned principally by the
Goldman Sachs Funds, which owns 36.5% of our common stock prior
to this offering and will own 30.7% of our common stock
following this offering, assuming all of the shares of common
stock offered hereby are sold and the underwriters do not
exercise their option to purchase additional shares; and
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Coffeyville Acquisition III refers to Coffeyville
Acquisition III LLC, the owner of the Partnerships
managing general partner, which in turn is owned by the Goldman
Sachs Funds, the Kelso Funds and certain members of CVR
Energys senior management team.
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Industry and
Market Data
The data included in this prospectus regarding the oil refining
industry and the nitrogen fertilizer industry, including trends
in the market and our position and the position of our
competitors within these industries, are based on our estimates,
which have been derived from managements knowledge and
experience in the areas in which the relevant businesses
operate, and information obtained from customers, distributors,
suppliers, trade and business organizations, internal research,
publicly
22
available information, industry publications and surveys and
other contacts in the areas in which the relevant businesses
operate. We have also cited information compiled by industry
publications, governmental agencies and publicly available
sources. Certain information contained in the Industry section
is based on the Energy Information Administrations Annual
Energy Outlook 2007, released in May 2007, which is the most
recent comprehensive EIA publication currently available.
Estimates of market size and relative positions in a market are
difficult to develop and inherently uncertain. Accordingly,
investors should not place undue weight on the industry and
market share data presented in this prospectus.
Trademarks, Trade
Names and Service Marks
This prospectus includes trademarks belonging to CVR Energy,
Inc., including COFFEYVILLE
RESOURCES
®
,
CVR
Energy
tm
and CVR
Partners
tm
.
This prospectus also contains trademarks, service marks,
copyrights and trade names of other companies.
23
RISK
FACTORS
You should carefully consider each of the following risks and
all of the information set forth in this prospectus before
deciding to invest in our common stock. If any of the following
risks and uncertainties develops into actual events, our
business, financial condition or results of operations could be
materially adversely affected. In that case, the price of our
common stock could decline and you could lose part or all of
your investment.
Risks Related to
Our Petroleum Business
Volatile
margins in the refining industry may cause volatility or a
decline in our future results of operations and decrease our
cash flow.
Our petroleum business financial results are primarily
affected by the relationship, or margin, between refined product
prices and the prices for crude oil and other feedstocks. Future
volatility in refining industry margins may cause volatility or
a decline in our results of operations, since the margin between
refined product prices and feedstock prices may decrease below
the amount needed for us to generate net cash flow sufficient
for our needs. Although an increase or decrease in the price for
crude oil generally results in a similar increase or decrease in
prices for refined products, there is normally a time lag in the
realization of the similar increase or decrease in prices for
refined products. The effect of changes in crude oil prices on
our results of operations therefore depends in part on how
quickly and how fully refined product prices adjust to reflect
these changes. A substantial or prolonged increase in crude oil
prices without a corresponding increase in refined product
prices, or a substantial or prolonged decrease in refined
product prices without a corresponding decrease in crude oil
prices, could have a significant negative impact on our
earnings, results of operations and cash flows. In 2008 we have
experienced extremely high oil prices. These high prices have
had an adverse effect on the profitability of oil refineries
generally, including us. If oil prices remain at their current
levels or move higher, our profitability will be materially
adversely effected.
If we are
required to obtain our crude oil supply without the benefit of
our credit intermediation agreement, our exposure to the risks
associated with volatile crude prices may increase and our
liquidity may be reduced.
We currently obtain the majority of our crude oil supply through
a crude oil credit intermediation agreement with J. Aron, which
minimizes the amount of in transit inventory and mitigates crude
pricing risks by ensuring pricing takes place extremely close to
the time when the crude is refined and the yielded products are
sold. In the event this agreement is terminated or is not
renewed prior to expiration we may be unable to obtain similar
services from another party at the same or better terms as our
existing agreement. The current credit intermediation agreement
expires on December 31, 2008 and will automatically extend
for an additional one year term unless either party elects not
to extend the agreement. Further, if we were required to obtain
our crude oil supply without the benefit of an intermediation
agreement, our exposure to crude pricing risks may increase,
even despite any hedging activity in which we may engage, and
our liquidity would be negatively impacted due to the increased
inventory and the negative impact of market volatility.
Our internally
generated cash flows and other sources of liquidity may not be
adequate for our capital needs.
If we cannot generate adequate cash flow or otherwise secure
sufficient liquidity to meet our working capital needs or
support our short-term and long-term capital requirements, we
may be unable to meet our debt obligations, including payments
on the notes, pursue our business strategies or comply with
certain environmental standards, which would have a material
adverse effect on our business and results of operations. As of
March 31, 2008 and June 16, 2008, we had cash, cash
equivalents and
short-term
investments of $25.2 million and $71.4 million,
respectively, and up to
24
$112.6 million available under our revolving credit
facility as of both dates. In the current crude oil price
environment, working capital is subject to substantial
variability from week-to-week and month-to-month. We have
substantial short-term and long-term capital needs. Our
short-term working capital needs are primarily crude oil
purchase requirements, which fluctuate with the pricing and
sourcing of crude oil. In 2008 we have experienced extremely
high oil prices which have substantially increased our
short-term working capital needs. Our long-term capital needs
include capital expenditures we are required to make to comply
with Tier II gasoline standards, on-road diesel
regulations, off-road diesel regulations and the Consent Decree.
We also have significant short-term and long-term needs for
cash, including deferred payments of $123.7 million plus
accrued interest ($5.8 million as of June 1, 2008) due on
August 31, 2008 that are owed under the Cash Flow Swap with
J. Aron. We estimate that due to the Cash Flow Swap we also will
owe J. Aron approximately $54 million on July 8, 2008 for
crude oil we settled or will settle with respect to the quarter
ending June 30, 2008, based on June 16, 2008 pricing.
Our liquidity and earnings are materially negatively impacted by
the effects of the Cash Flow Swap through at least June 2009.
See Risks Related to our Entire Business Our
commodity derivative activities have historically resulted and
in the future could result in losses and in
period-to-period
earning volatility. In addition, we currently estimate
that mandatory capital and turnaround expenditures, excluding
the non-recurring capital expenditures required to comply with
Tier II gasoline standards, on-road diesel regulations,
off-road diesel regulations and the Consent Decree described
above, will average approximately $49 million per year over
the next five years.
Disruption of
our ability to obtain an adequate supply of crude oil could
reduce our liquidity and increase our costs.
Our refinery requires approximately 85,000 to 100,000 bpd
of crude oil in addition to the light sweet crude oil we gather
locally in Kansas, northern Oklahoma and southwest Nebraska. We
obtain a portion of our non-gathered crude oil, approximately
22% in 2007, from foreign sources such as Latin America, South
America, the Middle East, West Africa, Canada and the North Sea.
The actual amount of foreign crude oil we purchase is dependent
on market conditions and will vary from year to year. We are
subject to the political, geographic, and economic risks
attendant to doing business with suppliers located in those
regions. Disruption of production in any of such regions for any
reason could have a material impact on other regions and our
business. In the event that one or more of our traditional
suppliers becomes unavailable to us, we may be unable to obtain
an adequate supply of crude oil, or we may only be able to
obtain our crude oil supply at unfavorable prices. As a result,
we may experience a reduction in our liquidity and our results
of operations could be materially adversely affected.
Severe weather, including hurricanes along the U.S. Gulf
Coast, could interrupt our supply of crude oil. For example, the
hurricane season in 2005 produced a record number of named
storms, including hurricanes Katrina and Rita. The location and
intensity of these storms caused extreme amounts of damage to
both crude and natural gas production as well as extensive
disruption to many U.S. Gulf Coast refinery operations,
although we believe that substantially most of this refining
capacity has been restored. These events caused both price
spikes in the commodity markets as well as substantial increases
in crack spreads in absolute terms. Supplies of crude oil to our
refinery are periodically shipped from U.S. Gulf Coast
production or terminal facilities, including through the Seaway
Pipeline from the U.S. Gulf Coast to Cushing, Oklahoma.
U.S. Gulf Coast facilities could be subject to damage or
production interruption from hurricanes or other severe weather
in the future which could interrupt or materially adversely
affect our crude oil supply. If our supply of crude oil is
interrupted, our business, financial condition and results of
operations could be materially adversely impacted.
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Our
profitability is partially linked to the light/heavy and
sweet/sour crude oil price spreads. A decrease in either of the
spreads would negatively impact our profitability.
Our profitability is partially linked to the price spreads
between light and heavy crude oil and sweet and sour crude oil
within our plant capabilities. We prefer to refine heavier sour
crude oils because they have historically provided wider
refining margins than light sweet crude. Accordingly, any
tightening of the light/heavy or sweet/sour spreads could reduce
our profitability. The light/heavy and sweet/sour spread has
declined in recent months, which has resulted, and in the future
may continue to result, in a decline in profitability.
The new and
redesigned equipment in our facilities may not perform according
to expectations, which may cause unexpected maintenance and
downtime and could have a negative effect on our future results
of operations and financial condition.
During 2007 we upgraded all of the units in our refinery by
installing new equipment and redesigning older equipment to
improve refinery capacity. The installation and redesign of key
equipment involves significant risks and uncertainties,
including the following:
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our upgraded equipment may not perform at expected throughput
levels;
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the yield and product quality of new equipment may differ from
design; and
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redesign or modification of the equipment may be required to
correct equipment that does not perform as expected, which could
require facility shutdowns until the equipment has been
redesigned or modified.
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In the second half of 2007 we also repaired certain of our
equipment as a result of the flood. This repaired equipment is
subject to similar risks and uncertainties as described above.
Any of these risks associated with new equipment, redesigned
older equipment, or repaired equipment could lead to lower
revenues or higher costs or otherwise have a negative impact on
our future results of operations and financial condition.
If our access
to the pipelines on which we rely for the supply of our
feedstock and the distribution of our products is interrupted,
our inventory and costs may increase and we may be unable to
efficiently distribute our products.
If one of the pipelines on which we rely for supply of our crude
oil becomes inoperative, we would be required to obtain crude
oil for our refinery through an alternative pipeline or from
additional tanker trucks, which could increase our costs and
result in lower production levels and profitability. Similarly,
if a major refined fuels pipeline becomes inoperative, we would
be required to keep refined fuels in inventory or supply refined
fuels to our customers through an alternative pipeline or by
additional tanker trucks from the refinery, which could increase
our costs and result in a decline in profitability.
Our petroleum
business financial results are seasonal and generally
lower in the first and fourth quarters of the year, which may
cause volatility in the price of our common stock.
Demand for gasoline products is generally higher during the
summer months than during the winter months due to seasonal
increases in highway traffic and road construction work. As a
result, our results of operations for the first and fourth
calendar quarters are generally lower than for those for the
second and third quarters, which may cause volatility in the
price of our common stock. Further, reduced agricultural work
during the winter months somewhat depresses demand for diesel
fuel in the winter months. In addition to the overall
seasonality of our business, unseasonably cool weather in the
summer months
and/or
unseasonably warm weather in the winter months in the markets in
which we sell our petroleum products could have the effect of
reducing demand for gasoline and diesel fuel which could result
in lower prices and reduce operating margins.
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We face
significant competition, both within and outside of our
industry. Competitors who produce their own supply of
feedstocks, have extensive retail outlets, make alternative
fuels or have greater financial resources than we do may have a
competitive advantage over us.
The refining industry is highly competitive with respect to both
feedstock supply and refined product markets. We may be unable
to compete effectively with our competitors within and outside
of our industry, which could result in reduced profitability. We
compete with numerous other companies for available supplies of
crude oil and other feedstocks and for outlets for our refined
products. We are not engaged in the petroleum exploration and
production business and therefore we do not produce any of our
crude oil feedstocks. We do not have a retail business and
therefore are dependent upon others for outlets for our refined
products. We do not have any long-term arrangements for much of
our output. Many of our competitors in the United States as a
whole, and one of our regional competitors, obtain significant
portions of their feedstocks from company-owned production and
have extensive retail outlets. Competitors that have their own
production or extensive retail outlets with brand-name
recognition are at times able to offset losses from refining
operations with profits from producing or retailing operations,
and may be better positioned to withstand periods of depressed
refining margins or feedstock shortages.
A number of our competitors also have materially greater
financial and other resources than us, providing them the
ability to add incremental capacity in environments of high
crack spreads. These competitors have a greater ability to bear
the economic risks inherent in all phases of the refining
industry. An expansion or upgrade of our competitors
facilities, price volatility, international political and
economic developments and other factors are likely to continue
to play an important role in refining industry economics and may
add additional competitive pressure on us.
In addition, we compete with other industries that provide
alternative means to satisfy the energy and fuel requirements of
our industrial, commercial and individual consumers. The more
successful these alternatives become as a result of governmental
regulations, technological advances, consumer demand, improved
pricing or otherwise, the greater the impact on pricing and
demand for our products and our profitability. There are
presently significant governmental and consumer pressures to
increase the use of alternative fuels in the United States.
Environmental
laws and regulations will require us to make substantial capital
expenditures in the future.
Current or future federal, state and local environmental laws
and regulations could cause us to spend substantial amounts to
install controls or make operational changes to comply with
environmental requirements. In addition, future environmental
laws and regulations, or new interpretations of existing laws or
regulations, could limit our ability to market and sell our
products to end users. Any such new interpretations or future
environmental laws or governmental regulations could have a
material impact on the results of our operations.
In March 2004, we entered into a Consent Decree with the United
States Environmental Protection Agency, or the EPA, and the
Kansas Department of Health and Environment, or the KDHE, to
address certain allegations of Clean Air Act violations by
Farmland at the Coffeyville oil refinery in order to address the
alleged violations and eliminate liabilities going forward. The
overall costs of complying with the Consent Decree over the next
four years are expected to be approximately $41 million. To
date, we have met the deadlines and requirements of the Consent
Decree and we have not had to pay any stipulated penalties,
which are required to be paid for failure to comply with various
terms and conditions of the Consent Decree. Availability of
equipment and technology performance, as well as EPA
interpretations of provisions of the Consent Decree that differ
from ours, could affect our ability to meet the requirements
imposed by the Consent Decree and have a material adverse effect
on our results of operations, financial condition and
profitability.
We may agree to enter into a global settlement under EPAs
National Petroleum Refining Initiative, or the NPRI. The 2004
Consent Decree addressed two of the four marquee
issues under
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the NPRI. We may agree to enter into a new consent decree or
amend the existing Consent Decree to incorporate the marquee
issues that were not addressed in the 2004 consent decree. We do
not believe that addressing the remaining marquee issues would
have a material adverse effect on our results of operations,
financial condition and profitability.
We will incur capital expenditures over the next several years
in order to comply with regulations under the federal Clean Air
Act establishing stringent low sulfur content specifications for
our petroleum products, including the Tier II gasoline
standards, as well as regulations with respect to on- and
off-road diesel fuel, which are designed to reduce air emissions
from the use of these products. In February 2004, the EPA
granted us a hardship waiver, which will require us
to meet final low sulfur Tier II gasoline standards by
January 1, 2011. In 2007, as a result of the flood, our
refinery exceeded the average annual gasoline sulfur standard
mandated by the hardship waiver. We are re-negotiating
provisions of the hardship waiver and have agreed in principle
to meet the final low sulfur Tier II gasoline sulfur
standards by January 1, 2010 (one year earlier than
required under the hardship waiver) in consideration for the
EPAs agreement not to seek a penalty for the 2007 sulfur
exceedance. Compliance with the Tier II gasoline standards
and on-road diesel standards required us to spend approximately
$133 million during 2006 and approximately
$103 million during 2007, and we estimate that compliance
will require us to spend approximately $68 million between
2008 and 2010. Changes in equipment or construction costs could
require significantly greater expenditures.
Changes in our
credit profile may affect our relationship with our suppliers,
which could have a material adverse effect on our
liquidity.
Changes in our credit profile may affect the way crude oil
suppliers view our ability to make payments and may induce them
to shorten the payment terms of their invoices. Given the large
dollar amounts and volume of our feedstock purchases, a change
in payment terms may have a material adverse effect on our
liquidity and our ability to make payments to our suppliers.
Risks Related to
the Nitrogen Fertilizer Business
Natural gas
prices affect the price of the nitrogen fertilizers that the
nitrogen fertilizer business sells. Any decline in natural gas
prices could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions.
Because most nitrogen fertilizer manufacturers rely on natural
gas as their primary feedstock, and the cost of natural gas is a
large component (approximately 90% based on historical data) of
the total production cost of nitrogen fertilizers for natural
gas-based nitrogen fertilizer manufacturers, the price of
nitrogen fertilizers has historically generally correlated with
the price of natural gas. We are currently in a period of high
natural gas prices, and the price at which the nitrogen
fertilizer business is able to sell its nitrogen fertilizers is
near historical highs. However, natural gas prices are cyclical
and volatile and may decline at any time. The nitrogen
fertilizer business does not hedge against declining natural gas
prices. Any decline in natural gas prices could have a material
adverse impact on our results of operations, financial condition
and the ability of the nitrogen fertilizer business to make cash
distributions.
The nitrogen
fertilizer plant has high fixed costs. If nitrogen fertilizer
product prices fall below a certain level, which could be caused
by a reduction in the price of natural gas, the nitrogen
fertilizer business may not generate sufficient revenue to
operate profitably or cover its costs.
The nitrogen fertilizer plant has high fixed costs as discussed
in Managements Discussion and Analysis of Financial
Condition and Results of Operations Major Influences
on Results of Operations Nitrogen Fertilizer
Business. As a result, downtime or low productivity due to
reduced demand, interruptions because of adverse weather
conditions, equipment failures, low prices for
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nitrogen fertilizer or other causes can result in significant
operating losses. Unlike its competitors, whose primary costs
are related to the purchase of natural gas and whose fixed costs
are minimal, the nitrogen fertilizer business has high fixed
costs not dependent on the price of natural gas. We have no
control over natural gas prices, which can be highly volatile. A
decline in natural gas prices generally has the effect of
reducing the base sale price for nitrogen fertilizer products in
the market generally while the nitrogen fertilizer
business fixed costs will remain substantially unchanged
by the decline in natural gas prices. Any decline in the price
of nitrogen fertilizer products could have a material adverse
effect on our results of operations, financial condition and the
ability of the nitrogen fertilizer business to make cash
distributions.
The demand for
and pricing of nitrogen fertilizers have increased dramatically
in recent years. The nitrogen fertilizer business is cyclical
and volatile and historically, periods of high demand and
pricing have been followed by periods of declining prices and
declining capacity utilization. Such cycles expose us to
potentially significant fluctuations in our financial condition,
cash flows and results of operations, which could result in
volatility in the price of our common stock or an inability of
the nitrogen fertilizer business to make quarterly
distributions.
A significant portion of nitrogen fertilizer product sales
consists of sales of agricultural commodity products, exposing
us to fluctuations in supply and demand in the agricultural
industry. These fluctuations historically have had and could in
the future have significant effects on prices across all
nitrogen fertilizer products and, in turn, the nitrogen
fertilizer business financial condition, cash flows and
results of operations, which could result in significant
volatility in the price of our common stock or an inability of
the nitrogen fertilizer business to make distributions to us.
Nitrogen fertilizer products are commodities, the price of which
can be volatile. The prices of nitrogen fertilizer products
depend on a number of factors, including general economic
conditions, cyclical trends in end-user markets, supply and
demand imbalances, and weather conditions, which have a greater
relevance because of the seasonal nature of fertilizer
application. If seasonal demand exceeds the projections of the
nitrogen fertilizer business, its customers may acquire nitrogen
fertilizer from its competitors, and the profitability of the
nitrogen fertilizer business will be negatively impacted. If
seasonal demand is less than expected, the nitrogen fertilizer
business will be left with excess inventory that will have to be
stored or liquidated.
Demand for fertilizer products is dependent, in part, on demand
for crop nutrients by the global agricultural industry.
Nitrogen-based fertilizers are currently in high demand, driven
by a growing world population, changes in dietary habits and an
expanded use of corn for the production of ethanol. Supply is
affected by available capacity and operating rates, raw material
costs, government policies and global trade. The prices for
nitrogen fertilizers are currently extremely high. Nitrogen
fertilizer prices may not remain at current levels and could
fall, perhaps materially. A decrease in nitrogen fertilizer
prices would have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions.
Nitrogen
fertilizer products are global commodities, and the nitrogen
fertilizer business faces intense competition from other
nitrogen fertilizer producers.
The nitrogen fertilizer business is subject to intense price
competition from both U.S. and foreign sources, including
competitors operating in the Persian Gulf, the Asia-Pacific
region, the Caribbean, Russia and Ukraine. Nitrogen fertilizer
products are global commodities, with little or no product
differentiation, and customers make their purchasing decisions
principally on the basis of delivered price and availability of
the product. The nitrogen fertilizer business competes with a
number of U.S. producers and producers in other countries,
including state-owned and government-subsidized entities. The
United States and the European Union each have trade regulatory
measures in effect that are designed to address this type of
unfair trade, but there is no guarantee that such trade
regulatory measures will continue. Changes in these measures
could have a material adverse impact on the sales and
profitability of the particular products involved. Some
competitors have greater total
29
resources and are less dependent on earnings from fertilizer
sales, which makes them less vulnerable to industry downturns
and better positioned to pursue new expansion and development
opportunities. In addition, recent consolidation in the
fertilizer industry has increased the resources of several
competitors. In light of this industry consolidation, our
competitive position could suffer to the extent the nitrogen
fertilizer business is not able to expand its own resources
either through investments in new or existing operations or
through acquisitions, joint ventures or partnerships. In
addition, if natural gas prices in the United States were to
decline to a level that prompts those U.S. producers who
have previously closed production facilities to resume
fertilizer production, this would likely contribute to a global
supply/demand imbalance that could have a material adverse
effect on our results of operations, financial condition and the
ability of the nitrogen fertilizer business to make cash
distributions. An inability to compete successfully could result
in the loss of customers, which could adversely affect our sales
and profitability.
Adverse
weather conditions during peak fertilizer application periods
may have a material adverse effect on our results of operations,
financial condition and the ability of the nitrogen fertilizer
business to make cash distributions, because the agricultural
customers of the nitrogen fertilizer business are geographically
concentrated.
Sales of nitrogen fertilizer products by the nitrogen fertilizer
business to agricultural customers are concentrated in the Great
Plains and Midwest states and are seasonal in nature. For
example, the nitrogen fertilizer business generates greater net
sales and operating income in the spring. Accordingly, an
adverse weather pattern affecting agriculture in these regions
or during this season including flooding could have a negative
effect on fertilizer demand, which could, in turn, result in a
material decline in our net sales and margins and otherwise have
a material adverse effect on our results of operations,
financial condition and the ability of the nitrogen fertilizer
business to make cash distributions. Our quarterly results may
vary significantly from one year to the next due primarily to
weather-related shifts in planting schedules and purchase
patterns.
The nitrogen
fertilizer business results of operations, financial
condition and ability to make cash distributions may be
adversely affected by the supply and price levels of pet coke
and other essential raw materials.
Pet coke is a key raw material used by the nitrogen fertilizer
business in the manufacture of nitrogen fertilizer products.
Increases in the price of pet coke could have a material adverse
effect on the nitrogen fertilizer business results of
operations, financial condition and ability to make cash
distributions. Moreover, if pet coke prices increase the
nitrogen fertilizer business may not be able to increase its
prices to recover increased pet coke costs, because market
prices for the nitrogen fertilizer business nitrogen
fertilizer products are generally correlated with natural gas
prices, the primary raw material used by competitors of the
nitrogen fertilizer business, and not pet coke prices. Based on
the nitrogen fertilizer business current output, the
nitrogen fertilizer business obtains most (over 75% on average
during the last four years) of the pet coke it needs from our
adjacent oil refinery, and procures the remainder on the open
market. The nitrogen fertilizer business competitors are
not subject to changes in pet coke prices. The nitrogen
fertilizer business is sensitive to fluctuations in the price of
pet coke on the open market. Pet coke prices could significantly
increase in the future. The nitrogen fertilizer business might
also be unable to find alternative suppliers to make up for any
reduction in the amount of pet coke it obtains from our oil
refinery.
The nitrogen fertilizer business may not be able to maintain an
adequate supply of pet coke and other essential raw materials.
In addition, the nitrogen fertilizer business could experience
production delays or cost increases if alternative sources of
supply prove to be more expensive or difficult to obtain. If raw
material costs were to increase, or if the nitrogen fertilizer
plant were to experience an extended interruption in the supply
of raw materials, including pet coke, to its production
facilities, the nitrogen fertilizer business could lose sale
opportunities, damage its relationships with or lose
30
customers, suffer lower margins, and experience other material
adverse effects to its results of operations, financial
condition and ability to make cash distributions.
The nitrogen
fertilizer business relies on an air separation plant owned by
The Linde Group to provide oxygen, nitrogen and compressed dry
air to its gasifier. A deterioration in the financial condition
of The Linde Group, or a mechanical problem with the air
separation plant, could have a material adverse effect on our
results of operations, financial condition and the ability of
the nitrogen fertilizer business to make cash
distributions.
The nitrogen fertilizer business relies on an air separation
plant owned by The Linde Group, or Linde, to provide oxygen,
nitrogen and compressed dry air to its gasifier. The nitrogen
fertilizer business operations could be adversely affected
if there were a deterioration in Lindes financial
condition such that the operation of the air separation plant
were disrupted. Additionally, this air separation plant in the
past has experienced numerous momentary interruptions, thereby
causing interruptions in the nitrogen fertilizer business
gasifier operations. The nitrogen fertilizer business requires a
reliable supply of oxygen, nitrogen and compressed dry air. A
disruption of its supply could prevent it from producing its
products at current levels and could have a material adverse
effect on our results of operations, financial condition and
ability of the nitrogen fertilizer business to make cash
distributions.
Ammonia can be
very volatile and dangerous. Any liability for accidents
involving ammonia that cause severe damage to property and/or
injury to the environment and human health could have a material
adverse effect on our results of operations, financial condition
and the ability of the nitrogen fertilizer business to make cash
distributions. In addition, the costs of transporting ammonia
could increase significantly in the future.
The nitrogen fertilizer business manufactures, processes,
stores, handles, distributes and transports ammonia, which can
be very volatile and dangerous. Accidents, releases or
mishandling involving ammonia could cause severe damage or
injury to property, the environment and human health, as well as
a possible disruption of supplies and markets. Such an event
could result in lawsuits, fines, penalties and regulatory
enforcement proceedings, all of which could lead to significant
liabilities. Any damage to persons, equipment or property or
other disruption of the ability of the nitrogen fertilizer
business to produce or distribute its products could result in a
significant decrease in operating revenues and significant
additional cost to replace or repair and insure its assets,
which could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions. The nitrogen
fertilizer business experienced an ammonia release most recently
in August 2007. See Business Environmental
Matters Release Reporting.
In addition, the nitrogen fertilizer business may incur
significant losses or costs relating to the operation of
railcars used for the purpose of carrying various products,
including ammonia. Due to the dangerous and potentially toxic
nature of the cargo, in particular ammonia, a railcar accident
may have catastrophic results, including fires, explosions and
pollution. These circumstances may result in severe damage
and/or
injury to property, the environment and human health. In the
event of pollution, the nitrogen fertilizer business may be
strictly liable. If the nitrogen fertilizer business is strictly
liable, it could be held responsible even if it is not at fault
and complied with the laws and regulations in effect at the time
of the accident. Litigation arising from accidents involving
ammonia may result in the Partnership or us being named as a
defendant in lawsuits asserting claims for large amounts of
damages, which could have a material adverse effect on our
results of operations, financial condition and the ability of
the nitrogen fertilizer business to make cash distributions.
Given the risks inherent in transporting ammonia, the costs of
transporting ammonia could increase significantly in the future.
Ammonia is typically transported by railcar. A number of
initiatives are underway in the railroad and chemical industries
that may result in changes to railcar design in order to
minimize railway accidents involving hazardous materials. If any
such design changes are
31
implemented, or if accidents involving hazardous freight
increases the insurance and other costs of railcars, freight
costs of the nitrogen fertilizer business could significantly
increase.
The nitrogen
fertilizer business operations are dependent on a limited
number of
third-party
suppliers. Failure by key suppliers of oxygen, nitrogen and
electricity to perform in accordance with their contractual
obligations may have a negative effect upon our results of
operations and financial condition and the ability of the
nitrogen fertilizer business to make cash
distributions.
The nitrogen fertilizer operations depend in large part on the
performance of third-party suppliers, including Linde for the
supply of oxygen and nitrogen and the city of Coffeyville for
the supply of electricity. The contract with Linde extends
through 2020 and the electricity contract extends through 2019.
Should these suppliers fail to perform in accordance with the
existing contractual arrangements, the nitrogen fertilizer
business operations would be forced to a halt. Alternative
sources of supply of oxygen, nitrogen or electricity could be
difficult to obtain. Any shutdown of operations at the nitrogen
fertilizer business even for a limited period could have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions.
The nitrogen
fertilizer business relies on third party providers of
transportation services and equipment, which subjects us to
risks and uncertainties beyond our control that may have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions.
The nitrogen fertilizer business relies on railroad and trucking
companies to ship nitrogen fertilizer products to its customers.
The nitrogen fertilizer business also leases rail cars from rail
car owners in order to ship its products. These transportation
operations, equipment, and services are subject to various
hazards, including extreme weather conditions, work stoppages,
delays, spills, derailments and other accidents and other
operating hazards.
These transportation operations, equipment and services are also
subject to environmental, safety, and regulatory oversight. Due
to concerns related to terrorism or accidents, local, state and
federal governments could implement new regulations affecting
the transportation of the nitrogen fertilizers business
products. In addition, new regulations could be implemented
affecting the equipment used to ship its products.
Any delay in the nitrogen fertilizer businesses ability to
ship its products as a result of these transportation
companies failure to operate properly, the implementation
of new and more stringent regulatory requirements affecting
transportation operations or equipment, or significant increases
in the cost of these services or equipment, could have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions.
Environmental
laws and regulations on fertilizer end-use and application could
have a material adverse impact on fertilizer demand in the
future.
Future environmental laws and regulations on the end-use and
application of fertilizers could cause changes in demand for the
nitrogen fertilizer business products. In addition, future
environmental laws and regulations, or new interpretations of
existing laws or regulations, could limit the ability of the
nitrogen fertilizer business to market and sell its products to
end users. From time to time, various state legislatures have
proposed bans or other limitations on fertilizer products. Any
such future laws, regulations or interpretations could have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions.
32
A major factor
underlying the current high level of demand for nitrogen-based
fertilizer products is the expanding production of ethanol. A
decrease in ethanol production, an increase in ethanol imports
or a shift away from corn as a principal raw material used to
produce ethanol could have a material adverse effect on our
results of operations, financial condition and the ability of
the nitrogen fertilizer business to make cash
distributions.
A major factor underlying the current high level of demand for
nitrogen-based fertilizer products is the expanding production
of ethanol in the United States and the expanded use of corn in
ethanol production. Ethanol production in the United States is
highly dependent upon a myriad of federal and state legislation
and regulations, and is made significantly more competitive by
various federal and state incentives. Such incentive programs
may not be renewed, or if renewed, they may be renewed on terms
significantly less favorable to ethanol producers than current
incentive programs. Recent studies showing that expanded ethanol
production may increase the level of greenhouse gases in the
environment may reduce political support for ethanol production.
The elimination or significant reduction in ethanol incentive
programs could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions.
Imported ethanol is generally subject to a $0.54 per gallon
tariff and a 2.5% ad valorem tax. This tariff is set to expire
on December 31, 2008. This tariff may not be renewed, or if
renewed, it may be renewed on terms significantly less favorable
for domestic ethanol production than current incentive programs.
We do not know the extent to which the volume of imports would
increase or the effect on U.S. prices for ethanol if the
tariff is not renewed beyond its current expiration. The
elimination of tariffs on imported ethanol may negatively impact
the demand for domestic ethanol, which could lower
U.S. corn and other grain production and thereby have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions.
Most ethanol is currently produced from corn and other raw
grains, such as milo or sorghum especially in the
Midwest. The current trend in ethanol production research is to
develop an efficient method of producing ethanol from
cellulose-based biomass, such as agricultural waste, forest
residue, municipal solid waste and energy crops (plants grown
for use to make biofuels or directly exploited for the energy
content). This trend is driven by the fact that cellulose-based
biomass is generally cheaper than corn, and producing ethanol
from cellulose-based biomass would create opportunities to
produce ethanol in areas that are unable to grow corn. Although
current technology is not sufficiently efficient to be
competitive, new conversion technologies may be developed in the
future. If an efficient method of producing ethanol from
cellulose-based biomass is developed, the demand for corn may
decrease, which could reduce demand for the nitrogen fertilizer
business products, which could have a material adverse
effect on our results of operations, financial condition and the
ability of the nitrogen fertilizer business to make cash
distributions.
If global
transportation costs decline, the nitrogen fertilizer
business competitors may be able to sell their products at
a lower price, which would have a material adverse effect on our
results of operations, financial condition and the ability of
the nitrogen fertilizer business to make cash
distributions.
Many of the nitrogen fertilizer business competitors
produce fertilizer outside of the U.S. farm belt region and
incur costs in transporting their products to this region via
ships and pipelines. There can be no assurance that
competitors transportation costs will not decline or that
additional pipelines will not be built, lowering the price at
which the nitrogen fertilizer business competitors can
sell their products, which would have a material adverse effect
on our results of operations, financial condition and the
ability of the nitrogen fertilizer business to make cash
distributions.
33
Risks Related to
Our Entire Business
Our refinery
and nitrogen fertilizer facilities face operating hazards and
interruptions, including unscheduled maintenance or downtime. We
could face potentially significant costs to the extent these
hazards or interruptions are not fully covered by our existing
insurance coverage. Insurance companies that currently insure
companies in the energy industry may cease to do so or may
substantially increase premiums in the future.
Our operations, located primarily in a single location, are
subject to significant operating hazards and interruptions. If
any of our facilities, including our refinery and the nitrogen
fertilizer plant, experiences a major accident or fire, is
damaged by severe weather, flooding or other natural disaster,
or is otherwise forced to curtail its operations or shut down,
we could incur significant losses which could have a material
adverse effect on our results of operations, financial condition
and the ability of the nitrogen fertilizer business to make cash
distributions. In addition, a major accident, fire, flood, crude
oil discharge or other event could damage our facilities or the
environment and the surrounding community or result in injuries
or loss of life. For example, the flood that occurred during the
weekend of June 30, 2007 shut down our refinery for seven
weeks, shut down the nitrogen fertilizer -facility for
approximately two weeks and required significant expenditures to
repair damaged equipment.
If our facilities experience a major accident or fire or other
event or an interruption in supply or operations, our business
could be materially adversely affected if the damage or
liability exceeds the amounts of business interruption,
property, terrorism and other insurance that we benefit from or
maintain against these risks and successfully collect. As
required under our existing credit facility, we maintain
property and business interruption insurance capped at
$1.25 billion which is subject to various deductibles and
sub-limits
for particular types of coverage (e.g., $300 million for a
loss caused by flood). In the event of a business interruption,
we would not be entitled to recover our losses until the
interruption exceeds 45 days in the aggregate. We are fully
exposed to losses in excess of this dollar cap and the various
sub-limits,
or business interruption losses that occur in the 45 days
of our deductible period. These losses may be material. For
example, a substantial portion of our lost revenue caused by the
business interruption following the flood that occurred during
the weekend of June 30, 2007 cannot be claimed because it
was lost within 45 days of the start of the flood.
If our refinery is forced to curtail its operations or shut down
due to hazards or interruptions like those described above, we
will still be obligated to make any required payments to J. Aron
under certain swap agreements we entered into in June 2005 (as
amended, the Cash Flow Swap). We will be required to
make payments under the Cash Flow Swap if crack spreads in
absolute terms rise above a certain level. Such payments could
have a material adverse impact on our financial results if, as a
result of a disruption to our operations, we are unable to
sustain sufficient revenues from which we can make such payments.
The energy industry is highly capital intensive, and the entire
or partial loss of individual facilities can result in
significant costs to both industry participants, such as us, and
their insurance carriers. In recent years, several large energy
industry claims have resulted in significant increases in the
level of premium costs and deductible periods for participants
in the energy industry. For example, during 2005, Hurricanes
Katrina and Rita caused significant damage to several petroleum
refineries along the U.S. Gulf Coast, in addition to
numerous oil and gas production facilities and pipelines in that
region. As a result of large energy industry claims, insurance
companies that have historically participated in underwriting
energy related facilities could discontinue that practice, or
demand significantly higher premiums or deductibles to cover
these facilities. Although we currently maintain significant
amounts of insurance, insurance policies are subject to annual
renewal. If significant changes in the number or financial
solvency of insurance underwriters for the energy industry
occur, we may be unable to obtain and maintain adequate
insurance at a reasonable cost or we might need to significantly
increase our retained exposures.
34
Our refinery consists of a number of processing units, many of
which have been in operation for a number of years. One or more
of the units may require unscheduled down time for unanticipated
maintenance or repairs on a more frequent basis than our
scheduled turnaround of every three to four years for each unit,
or our planned turnarounds may last longer than anticipated. The
nitrogen fertilizer plant, or individual units within the plant,
will require scheduled or unscheduled downtime for maintenance
or repairs. In general, the nitrogen fertilizer facility
requires scheduled turnaround maintenance every two years and
the next scheduled turnaround is currently expected to occur in
the fourth quarter of 2008. Scheduled and unscheduled
maintenance could reduce net income and cash flow during the
period of time that any of our units is not operating.
Our commodity
derivative activities have historically resulted and in the
future could result in losses and in
period-to-period
earnings volatility.
The nature of our operations results in exposure to fluctuations
in commodity prices. If we do not effectively manage our
derivative activities, we could incur significant losses. We
monitor our exposure and, when appropriate, utilize derivative
financial instruments and physical delivery contracts to
mitigate the potential impact from changes in commodity prices.
If commodity prices change from levels specified in our various
derivative agreements, a fixed price contract or an option price
structure could limit us from receiving the full benefit of
commodity price changes. In addition, by entering into these
derivative activities, we may suffer financial loss if we do not
produce oil to fulfill our obligations. In the event we are
required to pay a margin call on a derivative contract, we may
be unable to benefit fully from an increase in the value of the
commodities we sell. In addition, we may be required to make a
margin payment before we are able to realize a gain on a sale
resulting in a reduction in cash flow, particularly if prices
decline by the time we are able to sell.
In June 2005, Coffeyville Acquisition LLC entered into the Cash
Flow Swap, which is not subject to margin calls, in the form of
three swap agreements with J. Aron for the period from
July 1, 2005 to June 30, 2010. These agreements were
subsequently assigned from Coffeyville Acquisition LLC to
Coffeyville Resources, LLC on June 24, 2005. Based on crude
oil capacity of 115,000 bpd, the Cash Flow Swap represents
approximately 58% and 14% of crude oil capacity for the periods
July 1, 2008 through June 30, 2009 and July 1,
2009 through June 30, 2010, respectively. Under the terms
of our credit facility and upon meeting specific requirements
related to our leverage ratio and our credit ratings, we may
reduce the Cash Flow Swap to 35,000 bpd, or approximately
30% of expected crude oil capacity, for the period from
April 1, 2008 through December 31, 2008 and terminate
the Cash Flow Swap in 2009 and 2010. Otherwise, under the terms
of our credit facility, management has limited discretion to
change the amount of hedged volumes under the Cash Flow Swap
therefore affecting our exposure to market volatility. The
current environment of high and rising crude oil prices has led
to higher crack spreads in absolute terms but significantly
narrower crack spreads as a percentage of crude oil prices. As a
result, the Cash Flow Swap, under which payments are calculated
based on crack spreads in absolute terms, has had and will
continue to have a material negative impact on our earnings. In
addition, because this derivative is based on NYMEX prices while
our revenue is based on prices in the Coffeyville supply area,
the contracts do not eliminate risk of price volatility. If the
price of products on NYMEX is different from the value
contracted in the swap, then we will receive from or owe to the
counterparty the difference on each unit of product that is
contracted in the swap. We have substantial payment obligations
to J. Aron in respect of the Cash Flow Swap. See Our
internally generated cash flows and other sources of liquidity
may not be adequate for our capital needs.
In addition, as a result of the accounting treatment of these
contracts, unrealized gains and losses are charged to our
earnings based on the increase or decrease in the market value
of the unsettled position and the inclusion of such derivative
gains or losses in earnings may produce significant
period-to-period
earnings volatility that is not necessarily reflective of our
underlying operating performance. The positions under the Cash
Flow Swap resulted in unrealized gains (losses) of
$126.8 million, $(103.2) million and
$(13.9) million for the years ended December 31, 2006
and
35
2007 and the three months ended March 31, 2008,
respectively. The positions under the Cash Flow Swap had a
significant negative impact on our earnings in 2007 and are
expected to continue to do so in 2008. As of March 31,
2008, a $1.00 change in quoted prices for the absolute crack
spreads utilized in the Cash Flow Swap would result in a
$36.2 million change to the fair value of derivative
commodity position and the same change to net income. See
Managements Discussion and Analysis of Financial
Condition and Results of Operations Critical
Accounting Policies Derivative Instruments and Fair
Value of Financial Instruments.
We may not
recover all of the costs we have incurred in connection with the
flood and crude oil discharge that occurred at our refinery in
June/July 2007.
We have incurred significant costs with respect to facility
repairs, environmental remediation and property damage
claims
.
During the weekend of June 30, 2007, torrential rains in
southeast Kansas caused the Verdigris River to overflow its
banks and flood the town of Coffeyville, Kansas. Our refinery
and nitrogen fertilizer plant, which are located in close
proximity to the Verdigris River, were severely flooded,
sustained major damage and required extensive repairs. Total
gross costs incurred and recorded as of March 31, 2008
related to the third party costs to repair the refinery and
fertilizer facilities were approximately $82.5 million and
$4.0 million, respectively. Additionally, other corporate
overhead and miscellaneous costs incurred and recorded in
connection with the flood as of March 31, 2008 were
approximately $19.3 million. We currently estimate that
approximately $2.1 million in third party costs related to
the repair of flood damaged property will be recorded in future
periods. In addition to the cost of repairing the facilities, we
experienced a significant revenue loss attributable to the
property damage during the period when the facilities were not
in operation.
Despite our efforts to secure the refinery prior to its
evacuation as a result of the flood, we estimate that 1,919
barrels (80,600 gallons) of crude oil and 226 barrels of crude
oil fractions were discharged from our refinery into the
Verdigris River flood waters beginning on or about July 1,
2007. We expect to substantially complete remediation of the
contamination caused by the crude oil discharge by July 31,
2008 and anticipate minor remediation activities thereafter.
Total net costs recorded as of March 31, 2008 associated
with remediation efforts and third party property damage
incurred by the crude oil discharge are approximately
$27.3 million. This amount is net of anticipated insurance
recoveries of $21.4 million.
As of March 31, 2008, we have recorded total gross costs
associated with the repair of, and other matters relating to the
damage to our facilities and with third party and property
damage remediation incurred due to the crude oil discharge of
approximately $154.5 million. Total anticipated insurance
recoveries of approximately $107.2 million have been
recorded as March 31, 2008 (of which $21.5 million has
already been received from insurance carriers by us), resulting
in a net cost of approximately $47.3 million. We have not
estimated any potential fines, penalties or claims that may be
imposed or brought by regulatory authorities or possible
additional damages arising from lawsuits related to the flood.
The ultimate cost of environmental remediation and third
party property damage is difficult to assess and could be higher
than our current estimates.
It is difficult to estimate the ultimate cost of environmental
remediation resulting from the crude oil discharge or the cost
of third party property damage that we will ultimately be
required to pay. The costs and damages that we ultimately pay
may be greater than the estimated amounts currently described in
our filings with the Securities and Exchange Commission (the
SEC). Such excess costs and damages could be
material.
We do not know which of our losses our insurers will
ultimately cover or when we will receive any insurance
recovery.
36
During the time of the 2007 flood and crude oil discharge,
Coffeyville Resources, LLC was covered by both property/business
interruption and liability insurance policies. We are in the
process of submitting claims to, responding to information
requests from, and negotiating with various insurers with
respect to costs and damages related to these incidents.
However, we do not know which of our losses, if any, the
insurers will ultimately cover or when we will receive any
recovery. We may not be able to recover all of the costs we have
incurred and losses we have suffered in connection with the 2007
flood and crude oil discharge. Further, we likely will not be
able to recover most of the business interruption losses we
incurred since a substantial portion of our facilities were
operational within 45 days of the start of the flood, and
our coverage for business interruption losses applies only if
the facilities were not operational for 45 days or more.
Environmental
laws and regulations could require us to make substantial
capital expenditures to remain in compliance or to remediate
current or future contamination that could give rise to material
liabilities.
Our operations are subject to a variety of federal, state and
local environmental laws and regulations relating to the
protection of the environment, including those governing the
emission or discharge of pollutants into the environment,
product specifications and the generation, treatment, storage,
transportation, disposal and remediation of solid and hazardous
waste and materials. Environmental laws and regulations that
affect our operations and processes and the margins for our
refined products are extensive and have become progressively
more stringent. Violations of these laws and regulations or
permit conditions can result in substantial penalties,
injunctive relief requirements compelling installation of
additional controls, civil and criminal sanctions, permit
revocations
and/or
facility shutdowns.
In addition, new environmental laws and regulations, new
interpretations of existing laws and regulations, increased
governmental enforcement of laws and regulations or other
developments could require us to make additional unforeseen
expenditures. Many of these laws and regulations are becoming
increasingly stringent, and the cost of compliance with these
requirements can be expected to increase over time. The
requirements to be met, as well as the technology and length of
time available to meet those requirements, continue to develop
and change. These expenditures or costs for environmental
compliance could have a material adverse effect on our results
of operations, financial condition and profitability.
Our business is inherently subject to accidental spills,
discharges or other releases of petroleum or hazardous
substances into the environment and neighboring areas. Past or
future spills related to any of our operations, including our
refinery, pipelines, product terminals, fertilizer plant or
transportation of products or hazardous substances from those
facilities, may give rise to liability (including strict
liability, or liability without fault, and potential cleanup
responsibility) to governmental entities or private parties
under federal, state or local environmental laws, as well as
under common law. For example, we could be held strictly liable
under the Comprehensive Environmental Responsibility,
Compensation and Liability Act, or CERCLA, for past or future
spills without regard to fault or whether our actions were in
compliance with the law at the time of the spills. Pursuant to
CERCLA and similar state statutes, we could be held liable for
contamination associated with facilities we currently own or
operate, facilities we formerly owned or operated and facilities
to which we transported or arranged for the transportation of
wastes or by-products containing hazardous substances for
treatment, storage, or disposal. In addition, we face liability
for alleged personal injury or property damage due to exposure
to chemicals or other hazardous substances located at or
released from our facilities. We may also face liability for
personal injury, property damage, natural resource damage or for
cleanup costs for the alleged migration of contamination or
other hazardous substances from our facilities to adjacent and
other nearby properties.
Two of our facilities, including our Coffeyville oil refinery
and the Phillipsburg terminal (which operated as a refinery
until 1991), have environmental contamination. We have assumed
Farmlands responsibilities under certain Resource
Conservation and Recovery Act, or RCRA, corrective action
37
orders related to contamination at or that originated from the
refinery (which includes portions of the nitrogen fertilizer
plant) and the Phillipsburg terminal. If significant unknown
liabilities that have been undetected to date by our extensive
soil and groundwater investigation and sampling programs arise
in the areas where we have assumed liability for the corrective
action, that liability could have a material adverse effect on
our results of operations and financial condition and may not be
covered by insurance.
For a discussion of environmental risks and impacts related to
the 2007 flood and crude oil discharge, see We
may not recover all of the costs we have incurred in connection
with the flood and crude oil discharge that occurred at our
refinery in June/July 2007.
CO
2
and other greenhouse gas emissions may be the subject of federal
or state legislation or regulated in the future by the EPA as an
air pollutant, requiring us to obtain additional permits,
install additional controls, or purchase credits to reduce
greenhouse gas emissions which could adversely affect our
financial performance.
The United States Congress has considered various proposals to
reduce greenhouse gas emissions, but none have become law, and
presently, there are no federal mandatory greenhouse gas
emissions requirements. While it is probable that Congress will
adopt some form of federal mandatory greenhouse gas emission
reductions legislation in the future, the timing and specific
requirements of any such legislation are uncertain at this time.
In the absence of existing federal regulations, a number of
states have adopted regional greenhouse gas initiatives to
reduce
CO
2
and other greenhouse gas emissions. In 2007, a group of Midwest
states, including Kansas (where our refinery and the nitrogen
fertilizer facility are located) formed the Midwestern
Greenhouse Gas Accord, which calls for the development of a
cap-and-trade
system to control greenhouse gas emissions and for the inventory
of such emissions. However, the individual states that have
signed on to the accord must adopt laws or regulations
implementing the trading scheme before it becomes effective, and
the timing and specific requirements of any such laws or
regulations in Kansas are uncertain at this time.
In 2007, the U.S. Supreme Court decided that
CO
2
is an air pollutant under the federal Clean Air Act for the
purposes of vehicle emissions. Similar lawsuits have been filed
seeking to require the EPA to regulate
CO
2
emissions from stationary sources, such as our refinery and the
fertilizer plant, under the federal Clean Air Act. Our refinery
and the nitrogen fertilizer plant produce significant amounts of
CO
2
that are vented into the atmosphere. If the EPA regulates
CO
2
emissions from facilities such as ours, we may have to apply for
additional permits, install additional controls to reduce
CO
2
emissions or take other as yet unknown steps to comply with
these potential regulations. For example, we may have to
purchase
CO
2
emission reduction credits to reduce our current emissions of
CO
2
or to offset increases in
CO
2
emissions associated with expansions of our operations.
Compliance with any future legislation or regulation of
greenhouse gas emissions, if it occurs, may have a material
adverse effect on our results of operations, financial condition
and profitability.
We are subject
to strict laws and regulations regarding employee and process
safety, and failure to comply with these laws and regulations
could have a material adverse effect on our results of
operations, financial condition and profitability.
We are subject to the requirements of the Occupational Safety
and Health Administration, or OSHA, and comparable state
statutes that regulate the protection of the health and safety
of workers. In addition, OSHA requires that we maintain
information about hazardous materials used or produced in our
operations and that we provide this information to employees,
state and local governmental authorities, and local residents.
Failure to comply with OSHA requirements, including general
industry standards, process safety standards and control of
occupational exposure to regulated substances, could have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions if we are subjected to significant fines
or compliance costs.
38
We have a
limited operating history as a stand-alone
company.
Our limited historical financial performance as a stand-alone
company makes it difficult for you to evaluate our business and
results of operations to date and to assess our future prospects
and viability. We have been operating during a recent period of
significant volatility in the refined products industry, and
recent growth in the profitability of the nitrogen fertilizer
products industry may not continue or could reverse. As a
result, our results of operations may be lower than we currently
expect and the price of our common stock may be volatile.
Because we
have transferred our nitrogen fertilizer business to a newly
formed limited partnership, we may be required in the future to
share increasing portions of the cash flows of the nitrogen
fertilizer business with third parties and we may in the future
be required to deconsolidate the nitrogen fertilizer business
from our consolidated financial statements.
In connection with our initial public offering in October 2007,
we transferred our nitrogen fertilizer business to a newly
formed limited partnership, whose managing general partner is a
new entity owned by our controlling stockholders and senior
management. Although we currently consolidate the Partnership in
our financial statements, over time an increasing portion of the
cash flow of the nitrogen fertilizer business will be
distributed to our managing general partner if the Partnership
increases its quarterly distributions above specified target
distribution levels. In addition, if in the future the
Partnership elects to pursue a public or private offering of
limited partner interests to third parties, the new limited
partners will also be entitled to receive cash distributions
from the Partnership. This may require us to deconsolidate. Our
historical financial statements do not reflect the new limited
partnership structure prior to October 24, 2007 or any
non-controlling interest that may be issued to the public in
connection with a future initial offering of the Partnership and
therefore our past financial performance may not be an accurate
indicator of future performance.
Both the
petroleum and nitrogen fertilizer businesses depend on
significant customers, and the loss of one or several
significant customers may have a material adverse impact on our
results of operations and financial condition.
The petroleum and nitrogen fertilizer businesses both have a
high concentration of customers. Our four largest customers in
the petroleum business represented 44.4%, 36.8% and 40.2% of our
petroleum sales for the years ended December 31, 2006 and
2007 and the three months ended March 31, 2008,
respectively. Further, in the aggregate, the top five ammonia
customers of the nitrogen fertilizer business represented 51.9%,
62.1% and 68.4% of its ammonia sales for the years ended
December 31, 2006 and 2007 and the three months ended
March 31, 2008, respectively, and the top five UAN
customers of the nitrogen fertilizer business represented 30.0%,
38.7% and 42.4% of its UAN sales, respectively, for the same
periods. Several significant petroleum, ammonia and UAN
customers each account for more than 10% of sales of petroleum,
ammonia and UAN, respectively. Given the nature of our business,
and consistent with industry practice, we do not have long-term
minimum purchase contracts with any of our customers. The loss
of one or several of these significant customers, or a
significant reduction in purchase volume by any of them, could
have a material adverse effect on our results of operations,
financial condition and the ability of the nitrogen fertilizer
business to make cash distributions.
The petroleum
and nitrogen fertilizer businesses may not be able to
successfully implement their business strategies, which include
completion of significant capital programs.
One of the business strategies of the petroleum and nitrogen
fertilizer businesses is to implement a number of capital
expenditure projects designed to increase productivity,
efficiency and profitability. Many factors may prevent or hinder
implementation of some or all of these projects, including
compliance with or liability under environmental regulations, a
downturn in refining margins, technical or mechanical problems,
lack of availability of capital and other factors. Costs and
delays have increased significantly during the past few years
and the large number of capital projects underway in
39
the industry has led to shortages in skilled craftsmen,
engineering services and equipment manufacturing. Failure to
successfully implement these profit-enhancing strategies may
materially adversely affect our business prospects and
competitive position. In addition, we expect to execute
turnarounds at our refinery every three to four years, which
involve numerous risks and uncertainties. These risks include
delays and incurrence of additional and unforeseen costs. The
next scheduled refinery turnaround will be in 2010. In addition,
development and implementation of business strategies for the
Partnership will be primarily the responsibility of the managing
general partner of the Partnership. The next scheduled
turnaround of the nitrogen fertilizer facility is currently
expected to occur in the fourth quarter of 2008.
The
acquisition strategy of our petroleum business and the nitrogen
fertilizer business involves significant risks.
Both our petroleum business and the nitrogen fertilizer business
will consider pursuing acquisitions and expansion projects in
order to continue to grow and increase profitability. However,
acquisitions and expansions involve numerous risks and
uncertainties, including intense competition for suitable
acquisition targets; the potential unavailability of financial
resources necessary to consummate acquisitions and expansions;
difficulties in identifying suitable acquisition targets and
expansion projects or in completing any transactions identified
on sufficiently favorable terms; and the need to obtain
regulatory or other governmental approvals that may be necessary
to complete acquisitions and expansions. In addition, any future
acquisitions may entail significant transaction costs and risks
associated with entry into new markets and lines of business. In
addition, even when acquisitions are completed, integration of
acquired entities can involve significant difficulties, such as:
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unforeseen difficulties in the acquired operations and
disruption of the ongoing operations of our petroleum business
and the nitrogen fertilizer business;
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failure to achieve cost savings or other financial or operating
objectives with respect to an acquisition;
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strain on the operational and managerial controls and procedures
of our petroleum business and the nitrogen fertilizer business,
and the need to modify systems or to add management resources;
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difficulties in the integration and retention of customers or
personnel and the integration and effective deployment of
operations or technologies;
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assumption of unknown material liabilities or regulatory
non-compliance issues;
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amortization of acquired assets, which would reduce future
reported earnings;
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possible adverse short-term effects on our cash flows or
operating results; and
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diversion of managements attention from the ongoing
operations of our business.
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Failure to manage these acquisition and expansion growth risks
could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions. There can be no
assurance that we will be able to consummate any acquisitions or
expansions, successfully integrate acquired entities, or
generate positive cash flow at any acquired company or expansion
project.
We are a
holding company and depend upon our subsidiaries for our cash
flow.
We are a holding company. Our subsidiaries conduct all of our
operations and own substantially all of our assets.
Consequently, our cash flow and our ability to meet our
obligations or to pay dividends or make other distributions in
the future will depend upon the cash flow of our subsidiaries
and the payment of funds by our subsidiaries to us in the form
of dividends, tax sharing payments or otherwise. In addition,
Coffeyville Resources, LLC, our indirect subsidiary, which is
the primary obligor
40
under our existing credit facility, is a holding company and its
ability to meet its debt service obligations depends on the cash
flow of its subsidiaries. The ability of our subsidiaries to
make any payments to us will depend on their earnings, the terms
of their indebtedness, including the terms of our credit
facility, tax considerations and legal restrictions. In
particular, our credit facility currently imposes significant
limitations on the ability of our subsidiaries to make
distributions to us and consequently our ability to pay
dividends to our stockholders. Distributions that we receive
from the Partnership will be primarily reinvested in our
business rather than distributed to our stockholders. See also
Risks Related to the Nitrogen Fertilizer
Business The nitrogen fertilizer business may not
have sufficient cash to enable it to make quarterly
distributions to us following the payment of expenses and fees
and the establishment of cash reserves and
Risks Related to the Limited Partnership
Structure Through Which We Hold Our Interest in the Nitrogen
Fertilizer Business Our rights to receive
distributions from the Partnership may be limited over
time.
Our
significant indebtedness may affect our ability to operate our
business, and may have a material adverse effect on our
financial condition and results of operations.
As of March 31, 2008, we had total debt outstanding of
$488.0 million, $37.4 million in funded letters of
credit outstanding and borrowing availability of
$112.6 million under our credit facility. After giving
effect to the concurrent convertible senior notes offering, we
would have had total debt outstanding of $613.0 million
($631.8 million if the underwriters exercise their over
allotment option), or $638.0 million ($656.8 million
if the underwriters exercise their over allotment option) of
total debt outstanding if the proposed senior secured credit
facility (as defined under Description of Our
Indebtedness Proposed Senior Secured Credit
Facility) had also been entered into at that time. We and
our subsidiaries may be able to incur significant additional
indebtedness in the future. If new indebtedness is added to our
current indebtedness, the risks described below could increase.
Our high level of indebtedness could have important
consequences, such as:
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making it more difficult to satisfy obligations to our
creditors, including holders of the convertible senior notes;
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limiting our ability to obtain additional financing to fund our
working capital, acquisitions, expenditures, debt service
requirements or for other purposes;
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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;
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limiting our ability to compete with other companies who are not
as highly leveraged;
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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;
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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;
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increasing our vulnerability to a downturn in general economic
conditions or in pricing of our products; and
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limiting our ability to react to changing market conditions in
our industry and in our customers industries.
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In addition, borrowings under our existing credit facility (and
the proposed senior secured credit facility, if we are
successful in obtaining it) bear interest at variable rates. If
market interest rates increase, such variable-rate debt will
create higher debt service requirements, which could adversely
affect our cash flow. Our interest expense for the year ended
December 31, 2007 was $61.1 million. A 1% increase or
decrease in the applicable interest rates under our credit
facility, using average debt outstanding at March 31, 2008,
would correspondingly change our interest expense by
approximately
41
$4.9 million per year. If our credit ratings decline in the
future, the interest rates we are charged on debt under our
existing credit facility will increase by up to 0.75%.
In addition to our debt service obligations, our operations
require substantial investments on a continuing basis. Our
ability to make scheduled debt payments, including payments on
the notes, to refinance our obligations with respect to our
indebtedness and to fund capital and non-capital expenditures
necessary to maintain the condition of our operating assets,
properties and systems software, as well as to provide capacity
for the growth of our business, depends on our financial and
operating performance, which, in turn, is subject to prevailing
economic conditions and financial, business, competitive, legal
and other factors. In addition, we are and will be subject to
covenants contained in agreements governing our present and
future indebtedness. These covenants include and will likely
include restrictions on certain payments, the granting of liens,
the incurrence of additional indebtedness, dividend restrictions
affecting subsidiaries, asset sales, transactions with
affiliates and mergers and consolidations. Any failure to comply
with these covenants could result in a default under our credit
facility and the indenture governing the notes. Upon a default,
unless waived, the lenders under our credit facility would have
all remedies available to a secured lender, and could elect to
terminate their commitments, cease making further loans,
institute foreclosure proceedings against our or our
subsidiaries assets, and force us and our subsidiaries
into bankruptcy or liquidation. In addition, any defaults under
the credit facility, the indenture governing the notes or any
other debt could trigger cross defaults under other or future
credit agreements. Our operating results may not be sufficient
to service our indebtedness or to fund our other expenditures
and we may not be able to obtain financing to meet these
requirements.
If the
managing general partner of the Partnership elects to pursue a
public or private offering of Partnership interests, we will be
required to use our commercially reasonable efforts to amend our
credit facility to remove the Partnership as a guarantor. Any
such amendment could result in increased fees to us or other
onerous terms in our credit facility. In addition, we may not be
able to obtain such an amendment on terms acceptable to us or at
all.
If the managing general partner of the Partnership elects to
pursue a public or private offering of the Partnership, we will
be required to obtain amendments to our credit facility, as well
as to the Cash Flow Swap, in order to remove the Partnership and
its subsidiaries as obligors under such instruments. Such
amendments could be very expensive to obtain. Moreover, any such
amendments could result in significant changes to our credit
facilitys pricing, mandatory repayment provisions,
covenants and other terms and could result in increased interest
costs and require payment by us of additional fees. We have
agreed to use our commercially reasonable efforts to obtain such
amendments if the managing general partner elects to cause the
Partnership to pursue a public or private offering and gives us
at least 90 days written notice. However, we may not be
able to obtain any such amendment on terms acceptable to us or
at all. If we are not able to amend our credit facility on terms
satisfactory to us, we may need to refinance it with other
facilities. We will not be considered to have used our
commercially reasonable efforts to obtain such
amendments if we do not effect the requested modifications due
to (i) payment of fees to the lenders or the swap
counterparty, (ii) the costs of this type of amendment,
(iii) an increase in applicable margins or spreads or
(iv) changes to the terms required by the lenders including
covenants, events of default and repayment and prepayment
provisions; provided that (i), (ii), (iii) and (iv) in
the aggregate are not likely to have a material adverse effect
on us.
If we lose any
of our key personnel, we may be unable to effectively manage our
business or continue our growth.
Our future performance depends to a significant degree upon the
continued contributions of our senior management team and key
technical personnel. The loss or unavailability to us of any
member of our senior management team or a key technical employee
could negatively affect our ability to operate our business and
pursue our strategy. We face competition for these professionals
from our competitors, our customers and other companies
operating in our industry. To the extent that the
42
services of members of our senior management team and key
technical personnel would be unavailable to us for any reason,
we would be required to hire other personnel to manage and
operate our company and to develop our products and strategy. We
may not be able to locate or employ such qualified personnel on
acceptable terms or at all.
A substantial
portion of our workforce is unionized and we are subject to the
risk of labor disputes and adverse employee relations, which may
disrupt our business and increase our costs.
As of March 31, 2008, approximately 42% of our employees,
all of whom work in our petroleum business, were represented by
labor unions under collective bargaining agreements expiring in
2009. We may not be able to renegotiate our collective
bargaining agreements when they expire on satisfactory terms or
at all. A failure to do so may increase our costs. In addition,
our existing labor agreements may not prevent a strike or work
stoppage at any of our facilities in the future, and any work
stoppage could negatively affect our results of operations and
financial condition.
The
requirements of being a public company, including compliance
with the reporting requirements of the Exchange Act and the
requirements of the Sarbanes-Oxley Act, may strain our
resources, increase our costs and distract management, and we
may be unable to comply with these requirements in a timely or
cost-effective manner.
We are subject to the reporting requirements of the Securities
Exchange Act of 1934 (the Exchange Act) and the
corporate governance standards of the Sarbanes-Oxley Act of 2002
(the Sarbanes-Oxley Act). These requirements may
place a strain on our management, systems and resources. The
Exchange Act requires that we file annual, quarterly and current
reports with respect to our business and financial condition.
The Sarbanes-Oxley Act requires that we maintain effective
disclosure controls and procedures and internal control over
financial reporting. In order to maintain and improve the
effectiveness of our disclosure controls and procedures and
internal control over financial reporting, significant resources
and management oversight will be required. This may divert
managements attention from other business concerns, which
could have a material adverse effect on our business, financial
condition, results of operations and the price of our common
stock.
In April 2008, we concluded that our consolidated financial
statements for the year ended December 31, 2007 and the
related quarter ended September 30, 2007 contained errors
principally related to the calculation of the cost of crude oil
purchased by us and associated financial transactions. As a
result of these errors, management concluded that our internal
controls were not adequate to determine the cost of crude oil at
September 30, 2007 and December 31, 2007.
Specifically, the Companys policies and procedures for
estimating the cost of crude oil and reconciling these estimates
to vendor invoices were not effective. Additionally, the
Companys supervision and review of this estimation and
reconciliation process was not operating at a level of detail
adequate to identify the deficiencies in the process. Management
concluded that these deficiencies were material weaknesses in
our internal control over financial reporting. Due to these
material weaknesses, our management also concluded that we did
not maintain effective disclosure controls and procedures as of
December 31, 2007.
In order to remediate the material weaknesses described above,
our management is in the process of designing, implementing and
enhancing controls to ensure the proper accounting for the
calculation of the cost of crude oil. These remedial actions
include, among other things, (1) centralizing all crude oil
cost accounting functions, (2) adding additional layers of
accounting review with respect to our crude oil cost accounting
and (3) adding additional layers of business review with
respect to the computation of our crude oil costs.
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We will be
exposed to risks relating to evaluations of controls required by
Section 404 of the Sarbanes-Oxley Act.
We are in the process of evaluating our internal control systems
to allow management to report on, and our independent auditors
to audit, our internal control over financial reporting. We will
be performing the system and process evaluation and testing (and
any necessary remediation) required to comply with the
management certification and auditor attestation requirements of
Section 404 of the Sarbanes-Oxley Act, and will be required
to comply with Section 404 in our annual report for the
year ended December 31, 2008 (subject to any change in
applicable SEC rules). Furthermore, upon completion of this
process, we may identify control deficiencies of varying degrees
of severity under applicable SEC and Public Company Accounting
Oversight Board (PCAOB) rules and regulations that
remain unremediated. Although we produce our financial
statements in accordance with GAAP, our internal accounting
controls may not currently meet all standards applicable to
companies with publicly traded securities. We will be required
to report, among other things, control deficiencies that
constitute a material weakness or changes in
internal controls that, or that are reasonably likely to,
materially affect internal control over financial reporting. A
material weakness is a deficiency, or a combination
of deficiencies, in internal control over financial reporting,
such that there is a reasonable possibility that a material
misstatement of the annual or interim financial statements will
not be prevented or detected on a timely basis.
If we fail to implement the requirements of Section 404 in
a timely manner, we might be subject to sanctions or
investigation by regulatory authorities such as the SEC or the
PCAOB. If we do not implement improvements to our disclosure
controls and procedures or to our internal control over
financial reporting in a timely manner, our independent
registered public accounting firm may not be able to certify as
to the effectiveness of our internal control over financial
reporting pursuant to an audit of our internal control over
financial reporting. This may subject us to adverse regulatory
consequences or a loss of confidence in the reliability of our
financial statements. We could also suffer a loss of confidence
in the reliability of our financial statements if our
independent registered public accounting firm reports a material
weakness in our internal controls, if we do not develop and
maintain effective controls and procedures or if we are
otherwise unable to deliver timely and reliable financial
information. Any loss of confidence in the reliability of our
financial statements or other negative reaction to our failure
to develop timely or adequate disclosure controls and procedures
or internal control over financial reporting could result in a
decline in the price of our common stock. In addition, if we
fail to remedy any material weakness, our financial statements
may be inaccurate, we may face restricted access to the capital
markets and the price of our common stock may be adversely
affected.
We are a
controlled company within the meaning of the New
York Stock Exchange rules and, as a result, qualify for, and are
relying on, exemptions from certain corporate governance
requirements.
A company of which more than 50% of the voting power is held by
an individual, a group or another company is a controlled
company within the meaning of the New York Stock Exchange
rules and may elect not to comply with certain corporate
governance requirements of the New York Stock Exchange,
including:
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the requirement that a majority of our board of directors
consist of independent directors;
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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
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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.
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We are relying on all of these exemptions as a controlled
company. Accordingly, our stockholders do not have the same
protections afforded to stockholders of companies that are
subject to all of the corporate governance requirements of the
New York Stock Exchange.
New
regulations concerning the transportation of hazardous
chemicals, risks of terrorism and the security of chemical
manufacturing facilities could result in higher operating
costs.
The costs of complying with regulations relating to the
transportation of hazardous chemicals and security associated
with the refining and nitrogen fertilizer facilities may have a
material adverse effect on our results of operations, financial
condition and the ability of the nitrogen fertilizer business to
make cash distributions. Targets such as refining and chemical
manufacturing facilities may be at greater risk of future
terrorist attacks than other targets in the United States. As a
result, the petroleum and chemical industries have responded to
the issues that arose due to the terrorist attacks on
September 11, 2001 by starting new initiatives relating to
the security of petroleum and chemical industry facilities and
the transportation of hazardous chemicals in the United States.
Future terrorist attacks could lead to even stronger, more
costly initiatives. Simultaneously, local, state and federal
governments have begun a regulatory process that could lead to
new regulations impacting the security of refinery and chemical
plant locations and the transportation of petroleum and
hazardous chemicals. Our business or our customers
businesses could be materially adversely affected by the cost of
complying with new regulations.
We may face
third-party claims of intellectual property infringement, which
if successful could result in significant costs for our
business.
There are currently no claims pending against us relating to the
infringement of any third-party intellectual property rights.
However, in the future we may face claims of infringement that
could interfere with our ability to use technology that is
material to our business operations. Any litigation of this
type, whether successful or unsuccessful, could result in
substantial costs to us and diversions of our resources, either
of which could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions. In the event a
claim of infringement against us is successful, we may be
required to pay royalties or license fees for past or continued
use of the infringing technology, or we may be prohibited from
using the infringing technology altogether. If we are prohibited
from using any technology as a result of such a claim, we may
not be able to obtain licenses to alternative technology
adequate to substitute for the technology we can no longer use,
or licenses for such alternative technology may only be
available on terms that are not commercially reasonable or
acceptable to us. In addition, any substitution of new
technology for currently licensed technology may require us to
make substantial changes to our manufacturing processes or
equipment or to our products and could have a material adverse
effect on our results of operations, financial condition and the
ability of the nitrogen fertilizer business to make cash
distributions.
If licensed
technology is no longer available, the refinery and nitrogen
fertilizer businesses may be adversely affected.
We have licensed, and may in the future license, a combination
of patent, trade secret and other intellectual property rights
of third parties for use in our business. If any of these
license agreements were to be terminated, licenses to
alternative technology may not be available, or may only be
available on terms that are not commercially reasonable or
acceptable. In addition, any substitution of new technology for
currently licensed technology may require substantial changes to
manufacturing processes or equipment and may have a material
adverse effect on our results of operations, financial condition
and the ability of the nitrogen fertilizer business to make cash
distributions.
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Risks Related to
Our Common Stock
If our stock
price fluctuates, investors could lose a significant part of
their investment.
The market price of our common stock may be influenced by many
factors including:
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the failure of securities analysts to cover our common stock or
changes in financial estimates by analysts;
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announcements by us or our competitors of significant contracts
or acquisitions;
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variations in quarterly results of operations;
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loss of a large customer or supplier;
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general economic conditions;
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terrorist acts;
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future sales of our common stock; and
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investor perceptions of us and the industries in which our
products are used.
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As a result of these factors, investors in our common stock may
not be able to resell their shares at or above the price at
which they purchase our common stock. In addition, the stock
market in general has experienced extreme price and volume
fluctuations that have often been unrelated or disproportionate
to the operating performance of companies like us. These broad
market and industry factors may materially reduce the market
price of our common stock, regardless of our operating
performance.
Following the
completion of this offering, the Goldman Sachs Funds and the
Kelso Funds will continue to control us and may have conflicts
of interest with other stockholders. Conflicts of interest may
arise because our principal stockholders or their affiliates
have continuing agreements and business relationships with
us.
Upon completion of this offering, the Goldman Sachs Funds will
control 30.7% of our outstanding common stock, or 29.8% if the
underwriters exercise their option in full, and the Kelso Funds
will control 30.7% of our outstanding common stock, or 29.8% if
the underwriters exercise their option in full. Due to their
equity ownership, the Goldman Sachs Funds and the Kelso Funds
are able to control the election of our directors, determine our
corporate and management policies and determine, without the
consent of our other stockholders, the outcome of any corporate
transaction or other matter submitted to our stockholders for
approval, including potential mergers or acquisitions, asset
sales and other significant corporate transactions. The Goldman
Sachs Funds and the Kelso Funds also have sufficient voting
power to amend our organizational documents.
Conflicts of interest may arise between our principal
stockholders and us. Affiliates of some of our principal
stockholders engage in transactions with our company. We obtain
the majority of our crude oil supply through a crude oil credit
intermediation agreement with J. Aron, a subsidiary of The
Goldman Sachs Group, Inc. and an affiliate of the Goldman Sachs
Funds, and Coffeyville Resources, LLC currently has entered into
commodity derivative contracts (swap agreements) with J. Aron
for the period from July 1, 2005 to June 30, 2010. In
addition, Goldman Sachs Credit Partners, L.P. is the joint lead
arranger for our credit facility. See Certain
Relationships and Related Party Transactions. Further, the
Goldman Sachs Funds and the Kelso Funds are in the business of
making investments in companies and may, from time to time,
acquire and hold interests in businesses that compete directly
or indirectly with us and they may either directly, or through
affiliates, also maintain business relationships with companies
that may directly compete with us. In general, the Goldman Sachs
Funds and the Kelso Funds or their affiliates could pursue
business interests or exercise their voting power as
stockholders in ways that are detrimental to us, but beneficial
to themselves or to other companies in which they invest or with
whom they have a material relationship. Conflicts of interest
could also
46
arise with respect to business opportunities that could be
advantageous to the Goldman Sachs Funds and the Kelso Funds and
they may pursue acquisition opportunities that may be
complementary to our business, and as a result, those
acquisition opportunities may not be available to us. Under the
terms of our certificate of incorporation, the Goldman Sachs
Funds and the Kelso Funds have no obligation to offer us
corporate opportunities. See Description of Capital
Stock Corporate Opportunities.
Other conflicts of interest may arise between our principal
stockholders and us because the Goldman Sachs Funds and the
Kelso Funds control the managing general partner of the
Partnership which holds the nitrogen fertilizer business. The
managing general partner manages the operations of the
Partnership (subject to our rights to participate in the
appointment, termination and compensation of the chief executive
officer and chief financial officer of the managing general
partner and our other specified joint management rights) and
also holds IDRs which, over time, entitle the managing general
partner to receive increasing percentages of the
Partnerships quarterly distributions if the Partnership
increases the amount of distributions. Although the managing
general partner has a fiduciary duty to manage the Partnership
in a manner beneficial to the Partnership and us (as a holder of
special units in the Partnership), the fiduciary duty is limited
by the terms of the partnership agreement and the directors and
officers of the managing general partner also have a fiduciary
duty to manage the managing general partner in a manner
beneficial to the owners of the managing general partner. The
interests of the owners of the managing general partner may
differ significantly from, or conflict with, our interests and
the interests of our stockholders.
Under the terms of the Partnerships partnership agreement,
the Goldman Sachs Funds and the Kelso Funds have no obligation
to offer the Partnership business opportunities. The Goldman
Sachs Funds and the Kelso Funds may pursue acquisition
opportunities for themselves that would be otherwise beneficial
to the nitrogen fertilizer business and, as a result, these
acquisition opportunities would not be available to the
Partnership. The partnership agreement provides that the owners
of its managing general partner, which include the Goldman Sachs
Funds and the Kelso Funds, are permitted to engage in separate
businesses that directly compete with the nitrogen fertilizer
business and are not required to share or communicate or offer
any potential business opportunities to the Partnership even if
the opportunity is one that the Partnership might reasonably
have pursued. The agreement provides that the owners of our
managing general partner will not be liable to the Partnership
or any unitholder for breach of any fiduciary or other duty by
reason of the fact that such person pursued or acquired for
itself any business opportunity.
As a result of these conflicts, the managing general partner of
the Partnership may favor its own interests
and/or
the
interests of its owners over our interests and the interests of
our stockholders (and the interests of the Partnership). In
particular, because the managing general partner owns the IDRs,
it may be incentivized to maximize future cash flows by taking
current actions which may be in its best interests over the long
term. See Risks Related to the Limited
Partnership Structure Through Which We Hold Our Interest in the
Nitrogen Fertilizer Business Our rights to receive
distributions from the Partnership may be limited over
time and Risks Related to the Limited
Partnership Structure Through Which We Hold Our Interest in the
Nitrogen Fertilizer Business The managing general
partner of the Partnership has a fiduciary duty to favor the
interests of its owners, and these interests may differ from, or
conflict with, our interests and the interests of our
stockholders. In addition, if the value of the managing
general partner interest were to increase over time, this
increase in value and any realization of such value upon a sale
of the managing general partner interest would benefit the
owners of the managing general partner, which are the Goldman
Sachs Funds, the Kelso Funds and our senior management, rather
than our company and our stockholders. Such increase in value
could be significant if the Partnership performs well. See
The Nitrogen Fertilizer Limited Partnership.
Further, decisions made by the Goldman Sachs Funds and the Kelso
Funds with respect to their shares of common stock could trigger
cash payments to be made by us to certain members of our senior
management under the Phantom Unit Plans. Phantom points granted
under the Coffeyville
47
Resources, LLC Phantom Unit Appreciation Plan (Plan I), or the
Phantom Unit Plan I, and phantom points that we granted
under the Coffeyville Resources, LLC Phantom Unit Appreciation
Plan (Plan II), or the Phantom Unit Plan II, represent a
contractual right to receive a cash payment when payment is made
in respect of certain profits interests in Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC.
Definitions of the terms phantom points, Phantom Unit Plan I and
Phantom Unit Plan II are contained in the section of this
prospectus entitled Glossary of Selected Terms. If
either the Goldman Sachs Funds or the Kelso Funds sell any of
the shares of common stock of CVR Energy which they beneficially
own through Coffeyville Acquisition LLC or Coffeyville
Acquisition II LLC, as applicable, they may then cause
Coffeyville Acquisition LLC or Coffeyville Acquisition II
LLC, as applicable, to make distributions to their members in
respect of their profits interests. Because payments under the
Phantom Unit Plans are triggered by payments in respect of
profit interests under the Coffeyville Acquisition LLC Agreement
and Coffeyville Acquisition II LLC Agreement, we would
therefore be obligated to make cash payments under the Phantom
Unit Plans. This could negatively affect our cash reserves,
which could have a material adverse effect our results of
operations, financial condition and cash flows. We estimate that
any such cash payments should not exceed $65 million,
assuming all of the shares of our common stock held by
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC were sold at $24.92 per share, which was the closing price
of our common stock on June 16, 2008.
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC have informed us that they intend to make distributions to
their members with the proceeds of this offering. Accordingly,
we estimate that in connection with this offering we will be
required to make cash payments pursuant to the Phantom Unit
Plans in an amount of approximately $3.5 million
($4.3 million if underwriters exercise their option to
purchase additional shares in full), assuming the shares of
common stock are sold at $24.92 per share, which was the closing
price of our common stock on June 16, 2008.
In addition, one of the Goldman Sachs Funds and one of the Kelso
Funds have each guaranteed 50% of our payment obligations under
the Cash Flow Swap in the amount of $123.7 million, plus
accrued interest ($5.8 million as of June 1, 2008).
These payments under the Cash Flow Swap are due in August 2008.
As a result of these guarantees, the Goldman Sachs Funds and the
Kelso Funds may have interests that conflict with those of our
other shareholders.
Since June 24, 2005, we have made two cash distributions to
the Goldman Sachs Funds and the Kelso Funds. One distribution,
in the aggregate amount of $244.7 million, was made in
December 2006. In addition, in October 2007, we made a special
dividend to the Goldman Sachs Funds and the Kelso Funds in an
aggregate amount of approximately $10.3 million, which they
contributed to Coffeyville Acquisition III LLC in
connection with the purchase of the managing general partner of
the Partnership from us.
As a result of these relationships, including their ownership of
the managing general partner of the Partnership, the interests
of the Goldman Sachs Funds and the Kelso Funds may not coincide
with the interests of our company or other holders of our common
stock. So long as the Goldman Sachs Funds and the Kelso Funds
continue to control a significant amount of the outstanding
shares of our common stock, the Goldman Sachs Funds and the
Kelso Funds will continue to be able to strongly influence or
effectively control our decisions, including potential mergers
or acquisitions, asset sales and other significant corporate
transactions. In addition, so long as the Goldman Sachs Funds
and the Kelso Funds continue to control the managing general
partner of the Partnership, they will be able to effectively
control actions taken by the Partnership (subject to our
specified joint management rights), which may not be in our
interests or the interest of our stockholders. See Certain
Relationships and Related Party Transactions.
48
Shares
eligible for future sale, and the convertible notes we may issue
concurrently with this offering, may cause the price of our
common stock to decline.
Sales of substantial amounts of our common stock in the public
market, or the perception that these sales may occur, could
cause the market price of our common stock to decline. This
could also impair our ability to raise additional capital
through the sale of our equity securities. Under our amended and
restated certificate of incorporation, we are authorized to
issue up to 350,000,000 shares of common stock, of which
86,141,291 shares of common stock were outstanding as of
the date of this prospectus. Of these shares, the
23,000,000 shares of common stock sold in our initial
public offering, the 27,100 shares of common stock granted
to our non-executive officer employees in connection with our
initial public offering and registered pursuant to a
Registration Statement on
Form S-8
filed with the SEC on October 24, 2007 and the shares of
common stock sold in this offering, will be freely transferable
without restriction or further registration under the Securities
Act by persons other than affiliates, as that term
is defined in Rule 144 under the Securities Act.
Further, shares of our common stock are reserved for issuance on
the exercise of stock options and on conversion of our
convertible notes, assuming the convertible senior notes
offering is consummated. To the extent we issue any shares of
our common stock upon conversion of the convertible notes, the
conversion or some or all of the convertible notes will dilute
the ownership interests of existing stockholders, including
those who purchase shares of common stock in this offering. In
addition, the existence of the convertible notes may encourage
short selling by market participants because the conversion of
the notes could depress the price of our common stock. Holders
of debt securities sold by CVR Energy, including the convertible
notes that we may offer concurrently with this offering, will be
preferred in right of payment to holders of our common stock.
Following this offering, Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC will own collectively
52,911,720 shares of our common stock. Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC each
have demand and piggyback registration rights with respect to
these shares. In connection with this offering, the selling
stockholders and our directors and officers will enter into lock
up agreements, pursuant to which they are expected to agree,
subject to certain exceptions, not to sell or transfer, directly
or indirectly, any additional shares of our common stock for a
period of 90 days from the date of this prospectus, subject
to extension in certain circumstances. See Shares Eligible
for Future Sale.
Convertible
notes that we may offer concurrently with this offering may
cause the price of our common stock to decline.
The price of our common stock could also be affected by possible
sales of our common stock by investors who view the convertible
notes as a more attractive means of equity participation in CVR
Energy and by hedging or arbitrage activity that we expect to
develop involving our common stock. The hedging or arbitrage
could, in turn, affect the trading price of our common stock.
The accounting
for the convertible notes we may issue concurrently with this
offering will result in our having to recognize interest expense
significantly more than the stated interest rate of the
convertible notes in our financial statements after the start of
our fiscal year beginning on January 1, 2009. This
accounting change could have a negative effect on the price of
our common stock.
The convertible notes will have a net share settlement feature.
Under the current accounting rules, for the purpose of
calculating diluted earnings per share, a net share settled
convertible security meeting certain requirements is accounted
for in a manner similar to nonconvertible debt, with the stated
coupon constituting interest expense and any shares issuable
upon conversion of the security being accounted for in a manner
similar to the treasury stock method. The effect of this method
is that the shares potentially issuable upon conversion of the
securities are not included in the calculation of
49
earnings per share until the conversion price is in the
money, and the issuer is then assumed to issue the number
of shares necessary to settle the conversion.
However, the Financial Accounting Standards Board
(FASB) recently posted FASB Staff Position
(FSP) No. APB
14-1
Accounting for Convertible Debt Instruments That May Be
Settled in Cash upon Conversion (Including Partial Cash
Settlements) (previously FSP APB
14-a),
which
will change the accounting treatment for net share settled
convertible securities. Under the final FSP, cash settled
convertible securities will be separated into their debt and
equity components. The value assigned to the debt component will
be the estimated fair value, as of the issuance date, of a
similar debt instrument without the conversion feature, and the
difference between the proceeds for the convertible debt and the
amount reflected as a debt liability will be recorded as
additional paid-in capital. As a result, the debt will be
recorded at a discount reflecting its below market coupon
interest rate. The debt will subsequently be accreted to its par
value over its expected life, with the rate of interest that
reflects the market rate at issuance being reflected on the
income statement. This change in methodology will affect the
calculations of net income and earnings per share for many
issuers of cash settled convertible securities.
Risks Related to
the Limited Partnership Structure Through Which
We Hold Our Interest in the Nitrogen Fertilizer
Business
Because we
neither serve as, nor control, the managing general partner of
the Partnership, the managing general partner may operate the
Partnership in a manner with which we disagree or which is not
in our interest.
CVR GP, LLC or Fertilizer GP, which is owned by our controlling
stockholders and senior management, is the managing general
partner of the Partnership which holds the nitrogen fertilizer
business. The managing general partner is authorized to manage
the operations of the nitrogen fertilizer business (subject to
our specified joint management rights), and we do not control
the managing general partner. Although our senior management
also serves as the senior management of Fertilizer GP, in
accordance with a services agreement among us, Fertilizer GP and
the Partnership, our senior management operates the Partnership
under the direction of the managing general partners board
of directors and Fertilizer GP has the right to select different
management at any time (subject to our joint right in relation
to the chief executive officer and chief financial officer of
the managing general partner). Accordingly, the managing general
partner may operate the Partnership in a manner with which we
disagree or which is not in the interests of our company and our
stockholders.
Our interest in the Partnership currently gives us defined
rights to participate in the management and governance of the
Partnership. These rights include the right to approve the
appointment, termination of employment and compensation of the
chief executive officer and chief financial officer of
Fertilizer GP, not to be exercised unreasonably, and to approve
specified major business transactions such as significant
mergers and asset sales. We also have the right to appoint two
directors to Fertilizer GPs board of directors. However,
we will lose the rights listed above if we fail to hold at least
15% of the units in the Partnership.
The amount of
cash the nitrogen fertilizer business has available for
distribution to us depends primarily on its cash flow and not
solely on its profitability. If the nitrogen fertilizer business
has insufficient cash to cover intended distribution payments,
it would need to reduce or eliminate distributions to us or, to
the extent permitted under agreements governing indebtedness
that the nitrogen fertilizer business may incur in the future,
fund a portion of its distributions with
borrowings.
The amount of cash the nitrogen fertilizer business has
available for distribution depends primarily on its cash flow,
including working capital borrowings, and not solely on
profitability, which
50
will be affected by non-cash items. As a result, the nitrogen
fertilizer business may make cash distributions during periods
when it records losses and may not make cash distributions
during periods when it records net income.
If the nitrogen fertilizer business does not have sufficient
cash to cover intended distribution payments, it would either
reduce or eliminate distributions or, to the extent permitted to
do so under any revolving line of credit or other debt facility
that the nitrogen fertilizer business may enter into in the
future, fund a portion of its distributions with borrowings. If
the nitrogen fertilizer business were to use borrowings under a
revolving line of credit or other debt facility to fund
distributions, its indebtedness levels would increase and its
ongoing debt service requirements would increase and therefore
it would have less cash available for future distributions and
other purposes, including the funding of its ongoing expenses.
This could negatively impact the nitrogen fertilizer
business financial condition, results of operations,
ability to pursue its business strategy and ability to make
future distributions. We cannot assure you that borrowings would
be available to the nitrogen fertilizer business under a
revolving line of credit or other debt facility to fund
distributions.
The
Partnership may elect not to or may be unable to consummate an
initial public offering or one or more private placements. This
could negatively impact the value and liquidity of our
investment in the Partnership, which could impact the value of
our common stock.
The Partnership may elect not to or may be unable to consummate
an initial public offering or an initial private offering. Any
public or private offering of interests by the Partnership will
be made at the discretion of the managing general partner of the
Partnership and will be subject to market conditions and to
achievement of a valuation which the Partnership finds
acceptable. Although the Partnership filed a registration
statement with the SEC in February 2008, the Partnership
subsequently requested that the registration statement be
withdrawn, and there can be no assurance that the Partnership
will file a new registration statement with the SEC in the
future. An initial public offering is subject to SEC review of a
registration statement, compliance with applicable securities
laws and the Partnerships ability to list Partnership
units on a national securities exchange. Similarly, any private
placement to a third party would depend on the
Partnerships ability to reach agreement on price and enter
into satisfactory documentation with a third party. Any such
transaction would also require third party approvals, including
consent of our lenders under our credit facility and the swap
counterparty under our Cash Flow Swap, which would be very
expensive. The Partnership may never consummate any of such
transactions on terms favorable to us, or at all. If no offering
by the Partnership is ever made, it could impact the value, and
certainly the liquidity, of our investment in the Partnership.
If the Partnership does not consummate an initial public
offering, the value of our investment in the Partnership could
be negatively impacted because the Partnership would not be able
to access public equity markets to fund capital projects and
would not have a liquid currency with which to make acquisitions
or consummate other potentially beneficial transactions. In
addition, we would not have a liquid market in which to sell
portions of our interest in the Partnership but rather would
need to monetize our interest in a privately negotiated sale if
we ever wished to create liquidity through a divestiture of our
nitrogen fertilizer business. In addition, if the Partnership
does not consummate an initial public offering by
October 24, 2009, Fertilizer GP can require us to purchase
its managing general partner in the Partnership. See
If the Partnership does not consummate an initial
offering by October 24, 2009, Fertilizer GP can require us
to purchase its managing general partner interest in the
Partnership. We may not have requisite funds to do so.
We have agreed
with the Partnership that we will not own or operate any
fertilizer business in the United States or abroad (with limited
exceptions).
We have entered into an omnibus agreement with the Partnership
in order to clarify and structure the division of corporate
opportunities between the Partnership and us. Under this
agreement, we have agreed not to engage in the production,
transportation or distribution, on a wholesale basis, of
fertilizers in the contiguous United States, subject to limited
exceptions (fertilizer restricted
51
business). The Partnership has agreed not to engage in the
ownership or operation within the United States of any refinery
with processing capacity greater than 20,000 bpd whose
primary business is producing transportation fuels or the
ownership or operation outside the United States of any
refinery, regardless of its processing capacity or primary
business (refinery restricted business).
With respect to any business opportunity other than those
covered by a fertilizer restricted business or a refinery
restricted business, we and the Partnership have agreed that the
Partnership will have a preferential right to pursue such
opportunities before we may pursue them. If the
Partnerships managing general partner elects not to cause
the Partnership to pursue the business opportunity, then we will
be free to pursue such opportunity. This provision and the
non-competition provisions described in the previous paragraph
will continue so long as we and certain of our affiliates
continue to own 50% or more of the outstanding units of the
Partnership.
Our rights to
receive distributions from the Partnership may be limited over
time.
As a holder of 30,333,333 special units (which may convert into
general partner
and/or
subordinated general partner units if the Partnership
consummates an initial public or private offering, and which we
may sell from time to time), we are entitled to receive a
quarterly distribution of $0.4313 per unit (or
$13.1 million per quarter in the aggregate, assuming we do
not sell any of our units) from the Partnership to the extent
the Partnership has sufficient available cash after
establishment of cash reserves and payment of fees and expenses
before any distributions are made in respect of the IDRs. The
Partnership is required to distribute all of its cash on hand at
the end of each quarter, less reserves established by the
managing general partner in its discretion. In addition, the
managing general partner, Fertilizer GP, will have no right to
receive distributions in respect of its IDRs (i) until the
Partnership has distributed all aggregate adjusted operating
surplus generated by the Partnership during the period from
October 24, 2007 through December 31, 2009 and
(ii) for so long as the Partnership or its subsidiaries are
guarantors under our credit facility.
However, distributions of amounts greater than the aggregate
adjusted operating surplus (as defined under The Nitrogen
Fertilizer Limited Partnership Cash Distributions by
the Partnership Definition of Adjusted Operating
Surplus) generated through December 31, 2009 will be
allocated between us and Fertilizer GP (and the holders of any
other interests in the Partnership), and in the future the
allocation will grant Fertilizer GP a greater percentage of the
Partnerships cash distributions as more cash becomes
available for distribution. After the Partnership has
distributed all adjusted operating surplus generated by the
Partnership during the period from October 24, 2007 through
December 31, 2009, if quarterly distributions exceed the
target of $0.4313 per unit, Fertilizer GP will be entitled to
increasing percentages of the distributions, up to 48% of the
distributions above the highest target level, in respect of its
IDRs. Therefore, we will receive a smaller percentage of
quarterly cash distributions from the Partnership if the
Partnership increases its quarterly distributions above the
target distribution levels. Because Fertilizer GP does not share
in adjusted operating surplus generated prior to
December 31, 2009, Fertilizer GP could be incentivized to
cause the Partnership to make capital expenditures for
maintenance prior to such date, which would reduce operating
surplus, rather than for expansion, which would not, and,
accordingly, affect the amount of operating surplus generated.
Fertilizer GP could also be incentivized to cause the
Partnership to make capital expenditures for maintenance prior
to December 31, 2009 that it would otherwise make at a
later date in order to reduce operating surplus generated prior
to such date. In addition, Fertilizer GPs discretion in
determining the level of cash reserves may materially adversely
affect the Partnerships ability to make cash distributions
to us.
Moreover, if the Partnership issues common units in a public or
private offering, at least 40% (and potentially all) of our
special units will become subordinated units. We will not be
entitled to any distributions on our subordinated units until
the common units issued in the public or private offering and
our GP units have received the minimum quarterly distribution
(MQD) of $0.375 per unit (which may be reduced
without our consent in connection with the public or private
offering, or could be increased with our consent), plus any
accrued and unpaid arrearages in the minimum quarterly
52
distribution from prior quarters. The managing general partner,
and not CVR Energy, has authority to decide whether or not to
pursue such an offering. As a result, our right to distributions
will diminish if the managing general partner decides to pursue
such an offering.
The managing
general partner of the Partnership has a fiduciary duty to favor
the interests of its owners, and these interests may differ
from, or conflict with, our interests and the interests of our
stockholders.
The managing general partner of the Partnership, Fertilizer GP,
is responsible for the management of the Partnership (subject to
our specified management rights). Although Fertilizer GP has a
fiduciary duty to manage the Partnership in a manner beneficial
to the Partnership and holders of interests in the Partnership
(including us, in our capacity as holder of special units), the
fiduciary duty is specifically limited by the express terms of
the partnership agreement and the directors and officers of
Fertilizer GP also have a fiduciary duty to manage Fertilizer GP
in a manner beneficial to the owners of Fertilizer GP. The
interests of the owners of Fertilizer GP may differ from, or
conflict with, our interests and the interests of our
stockholders. In resolving these conflicts, Fertilizer GP may
favor its own interests
and/or
the
interests of its owners over our interests and the interests of
our stockholders (and the interests of the Partnership). In
addition, while our directors and officers have a fiduciary duty
to make decisions in our interests and the interests of our
stockholders, one of our wholly-owned subsidiaries is also a
general partner of the Partnership and, therefore, in such
capacity, has a fiduciary duty to exercise rights as general
partner in a manner beneficial to the Partnership and its
unitholders, subject to the limitations contained in the
partnership agreement. As a result of these conflicts, our
directors and officers may feel obligated to take actions that
benefit the Partnership as opposed to us and our stockholders.
The potential conflicts of interest include, among others, the
following:
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Fertilizer GP, as managing general partner of the Partnership,
holds all of the IDRs in the Partnership. IDRs give Fertilizer
GP a right to increasing percentages of the Partnerships
quarterly distributions after the Partnership has distributed
all adjusted operating surplus generated by the Partnership
during the period from October 24, 2007 through
December 31, 2009, assuming the Partnership and its
subsidiaries are released from their guaranty of our credit
facility and if the quarterly distributions exceed the target of
$0.4313 per unit. Fertilizer GP may have an incentive to manage
the Partnership in a manner which preserves or increases the
possibility of these future cash flows rather than in a manner
that preserves or increases current cash flows.
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Fertilizer GP may also have an incentive to engage in conduct
with a high degree of risk in order to increase cash flows
substantially and thereby increase the value of the IDRs instead
of following a safer course of action.
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The owners of Fertilizer GP, who are also our controlling
stockholders and senior management, are permitted to compete
with us or the Partnership or to own businesses that compete
with us or the Partnership. In addition, the owners of
Fertilizer GP are not required to share business opportunities
with us, and our owners are not required to share business
opportunities with the Partnership or Fertilizer GP.
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Neither the partnership agreement nor any other agreement
requires the owners of Fertilizer GP to pursue a business
strategy that favors us or the Partnership. The owners of
Fertilizer GP have fiduciary duties to make decisions in their
own best interests, which may be contrary to our interests and
the interests of the Partnership. In addition, Fertilizer GP is
allowed to take into account the interests of parties other than
us, such as its owners, or the Partnership in resolving
conflicts of interest, which has the effect of limiting its
fiduciary duty to us.
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Fertilizer GP has limited its liability and reduced its
fiduciary duties under the partnership agreement and has also
restricted the remedies available to the unitholders of the
Partnership,
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including us, for actions that, without the limitations, might
constitute breaches of fiduciary duty. As a result of our
ownership interest in the Partnership, we may consent to some
actions and conflicts of interest that might otherwise
constitute a breach of fiduciary or other duties under
applicable state law.
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Fertilizer GP determines the amount and timing of asset
purchases and sales, capital expenditures, borrowings, repayment
of indebtedness, issuances of additional partnership interests
and cash reserves maintained by the Partnership (subject to our
specified joint management rights), each of which can affect the
amount of cash that is available for distribution to us in our
capacity as a holder of special units and the amount of cash
paid to Fertilizer GP in respect of its IDRs.
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Fertilizer GP will also able to determine the amount and timing
of any capital expenditures and whether a capital expenditure is
for maintenance, which reduces operating surplus, or expansion,
which does not. Such determinations can affect the amount of
cash that is available for distribution and the manner in which
the cash is distributed.
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In some instances Fertilizer GP may cause the Partnership to
borrow funds in order to permit the payment of cash
distributions, even if the purpose or effect of the borrowing is
to make incentive distributions, which may not be in our
interests.
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The partnership agreement permits the Partnership to classify up
to $60 million as operating surplus, even if this cash is
generated from asset sales, borrowings other than working
capital borrowings or other sources the distribution of which
would otherwise constitute capital surplus. This cash may be
used to fund distributions in respect of the IDRs.
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The partnership agreement does not restrict Fertilizer GP from
causing the nitrogen fertilizer business to pay it or its
affiliates for any services rendered to the Partnership or
entering into additional contractual arrangements with any of
these entities on behalf of the Partnership.
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Fertilizer GP may exercise its rights to call and purchase all
of the Partnerships equity securities of any class if at
any time it and its affiliates (excluding us) own more than 80%
of the outstanding securities of such class.
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Fertilizer GP controls the enforcement of obligations owed to
the Partnership by it and its affiliates. In addition,
Fertilizer GP decides whether to retain separate counsel or
others to perform services for the Partnership.
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Fertilizer GP determines which costs incurred by it and its
affiliates are reimbursable by the Partnership.
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The executive officers of Fertilizer GP, and the majority of the
directors of Fertilizer GP, also serve as our directors
and/or
executive officers. The executive officers who work for both us
and Fertilizer GP, including our chief executive officer, chief
operating officer, chief financial officer and general counsel,
divide their time between our business and the business of the
Partnership. These executive officers will face conflicts of
interest from time to time in making decisions which may benefit
either us or the Partnership.
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The
partnership agreement limits the fiduciary duties of the
managing general partner and restricts the remedies available to
us for actions taken by the managing general partner that might
otherwise constitute breaches of fiduciary duty.
The partnership agreement contains provisions that reduce the
standards to which Fertilizer GP, as the managing general
partner, would otherwise be held by state fiduciary duty law.
For example:
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The partnership agreement permits Fertilizer GP to make a number
of decisions in its individual capacity, as opposed to its
capacity as managing general partner. This entitles Fertilizer
GP to consider only the interests and factors that it desires,
and it has no duty or
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obligation to give any consideration to any interest of, or
factors affecting, us or our affiliates. Decisions made by
Fertilizer GP in its individual capacity will be made by the
sole member of Fertilizer GP, and not by the board of directors
of Fertilizer GP. Examples include the exercise of its limited
call right, its voting rights, its registration rights and its
determination whether or not to consent to any merger or
consolidation or amendment to the partnership agreement.
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The partnership agreement provides that Fertilizer GP will not
have any liability to the Partnership or to us for decisions
made in its capacity as managing general partner so long as it
acted in good faith, meaning it believed that the decisions were
in the best interests of the Partnership.
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The partnership agreement provides that Fertilizer GP and its
officers and directors will not be liable for monetary damages
to the Partnership for any acts or omissions unless there has
been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that Fertilizer GP or those
persons acted in bad faith or engaged in fraud or willful
misconduct, or in the case of a criminal matter, acted with
knowledge that such persons conduct was criminal.
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The partnership agreement generally provides that affiliate
transactions and resolutions of conflicts of interest not
approved by the conflicts committee of the board of directors of
Fertilizer GP and not involving a vote of unitholders must be on
terms no less favorable to the Partnership than those generally
provided to or available from unrelated third parties or be
fair and reasonable. In determining whether a
transaction or resolution is fair and reasonable,
Fertilizer GP may consider the totality of the relationship
between the parties involved, including other transactions that
may be particularly advantageous or beneficial to the
Partnership.
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The
Partnership has a preferential right to pursue corporate
opportunities before we can pursue them.
We have entered into an agreement with the Partnership in order
to clarify and structure the division of corporate opportunities
between us and the Partnership. Under this agreement, we have
agreed not to engage in the production, transportation or
distribution, on a wholesale basis, of fertilizers in the
contiguous United States, subject to limited exceptions
(fertilizer restricted business). In addition, the Partnership
has agreed not to engage in the ownership or operation within
the United States of any refinery with processing capacity
greater than 20,000 barrels per day whose primary business
is producing transportation fuels or the ownership or operation
outside the United States of any refinery (refinery restricted
business).
With respect to any business opportunity other than those
covered by a fertilizer restricted business or a refinery
restricted business, we have agreed that the Partnership will
have a preferential right to pursue such opportunities before we
may pursue them. If the managing general partner of the
Partnership elects not to pursue the business opportunity, then
we will be free to pursue such opportunity. This provision will
continue so long as we continue to own 50% of the outstanding
units of the Partnership. See The Nitrogen Fertilizer
Limited Partnership Intercompany
Agreements Omnibus Agreement.
If the
Partnership elects to pursue and completes a public offering or
private placement of limited partner interests, our voting power
in the Partnership would be reduced and our rights to
distributions from the Partnership could be materially adversely
affected.
Fertilizer GP may, in its sole discretion, elect to pursue one
or more public or private offerings of limited partner interests
in the Partnership. Fertilizer GP will have the sole authority
to determine the timing, size (subject to our joint management
rights for any initial offering in excess of $200 million,
exclusive of the underwriters option to purchase
additional limited partner interests, if any), and underwriters
or initial purchasers, if any, for such offerings, if any. Any
public or private offering of
55
limited partner interests could materially adversely affect us
in several ways. For example, if such an offering occurs, our
percentage interest in the Partnership would be diluted. Some of
our voting rights in the Partnership could thus become less
valuable, since we would not be able to take specified actions
without support of other unitholders. For example, since the
vote of 80% of unitholders is required to remove the managing
general partner in specified circumstances, if the managing
general partner sells more than 20% of the units to a third
party we would not have the right, unilaterally, to remove the
general partner under the specified circumstances.
In addition, if the Partnership completes an offering of limited
partner interests, the distributions that we receive from the
Partnership would decrease because the Partnerships
distributions will have to be shared with the new limited
partners, and the new limited partners right to
distributions will be superior to ours because at least 40% (and
potentially all) of our units will become subordinated units.
Pursuant to the terms of the partnership agreement, the new
limited partners and Fertilizer GP will have superior priority
to distributions in some circumstances. Subordinated units will
not be entitled to receive distributions unless and until all
common units and any other units senior to the subordinated
units have received the minimum quarterly distribution, plus any
accrued and unpaid arrearages in the MQD from prior quarters. In
addition, upon a liquidation of the Partnership, common
unitholders will have a preference over subordinated unitholders
in certain circumstances.
If the
Partnership does not consummate an initial offering by
October 24, 2009, Fertilizer GP can require us to purchase
its managing general partner interest in the Partnership. We may
not have requisite funds to do so.
If the Partnership does not consummate an initial private or
public offering by October 24, 2009, Fertilizer GP can
require us to purchase the managing general partner interest.
This put right expires on the earlier of
(1) October 24, 2012 and (2) the closing of the
Partnerships initial offering. The purchase price will be
the fair market value of the managing general partner interest,
as determined by an independent investment banking firm selected
by us and Fertilizer GP. Fertilizer GP will determine in its
discretion whether the Partnership will consummate an initial
offering.
If Fertilizer GP elects to require us to purchase the managing
general partner interest, we may not have available cash
resources to pay the purchase price. In addition, any purchase
of the managing general partner interest would divert our
capital resources from other intended uses, including capital
expenditures and growth capital. In addition, the instruments
governing our indebtedness may limit our ability to acquire, or
prohibit us from acquiring, the managing general partner
interest.
Fertilizer GP
can require us to be a selling unit holder in the
Partnerships initial offering at an undesirable time or
price.
If Fertilizer GP elects to cause the Partnership to undertake an
initial private or public offering, we have agreed that
Fertilizer GP may structure the initial offering to include
(1) a secondary offering of interests by us or (2) a
primary offering of interests by the Partnership, possibly
together with an incurrence of indebtedness by the Partnership,
where a use of proceeds is to redeem units from us (with a
per-unit
redemption price equal to the price at which a unit is purchased
from the Partnership, net of sales commissions or underwriting
discounts) (a special GP offering), provided that in
either case the number of units associated with the special GP
offering is reasonably expected by Fertilizer GP to generate no
more than $100 million in net proceeds to us. If Fertilizer
GP elects to cause the Partnership to undertake an initial
private or public offering, it may require us to sell (including
by redemption) a portion, which could be a substantial portion,
of our special units in the Partnership at a time or price we
would not otherwise have chosen. A sale of special units would
result in our receiving cash proceeds for the value of such
units, net of sales commissions and underwriting discounts. Any
such sale or redemption would likely result in taxable gain to
us. See Use of the limited partnership
structure involves tax risks. For example, the
Partnerships tax treatment depends on its status as a
partnership for federal income tax purposes, as well as it not
being subject to a material amount of
56
entity-level taxation by individual states. If the IRS were to
treat the Partnership as a corporation for federal income tax
purposes or if the Partnership were to become subject to
additional amounts of entity-level taxation for state tax
purposes, then its cash available for distribution to us would
be substantially reduced.
Our rights to
remove Fertilizer GP as managing general partner of the
Partnership are extremely limited.
Until October 24, 2012, Fertilizer GP may only be removed
as managing general partner if at least 80% of the outstanding
units of the Partnership vote for removal and there is a final,
non-appealable judicial determination that Fertilizer GP, as an
entity, has materially breached a material provision of the
partnership agreement or is liable for actual fraud or willful
misconduct in its capacity as a general partner of the
Partnership. Consequently, we will be unable to remove
Fertilizer GP unless a court has made a final, non-appealable
judicial determination in those limited circumstances as
described above. Additionally, if there are other holders of
partnership interests in the Partnership, these holders may have
to vote for removal of Fertilizer GP as well if we desire to
remove Fertilizer GP but do not hold at least 80% of the
outstanding units of the Partnership at that time.
After October 24, 2012, Fertilizer GP may be removed with
or without cause by a vote of the holders of at least 80% of the
outstanding units of the Partnership, including any units owned
by Fertilizer GP and its affiliates, voting together as a single
class. Therefore, we may need to gain the support of other
unitholders in the Partnership if we desire to remove Fertilizer
GP as managing general partner, if we do not hold at least 80%
of the outstanding units of the Partnership.
If the managing general partner is removed without cause, it
will have the right to convert its managing general partner
interest, including the IDRs, into units or to receive cash
based on the fair market value of the interest at the time. If
the managing general partner is removed for cause, a successor
managing general partner will have the option to purchase the
managing general partner interest, including the IDRs, of the
departing managing general partner for a cash payment equal to
the fair market value of the managing general partner interest.
Under all other circumstances, the departing managing general
partner will have the option to require the successor managing
general partner to purchase the managing general partner
interest of the departing managing general partner for its fair
market value.
In addition to removal, we have a right to purchase Fertilizer
GPs general partner interest in the Partnership, and
therefore remove Fertilizer GP as managing general partner, if
the Partnership has not made an initial private offering or an
initial public offering of limited partner interests by
October 24, 2012.
The nitrogen
fertilizer business may not have sufficient cash to enable it to
make quarterly distributions to us following the payment of
expenses and fees and the establishment of cash
reserves.
The nitrogen fertilizer business may not have sufficient cash
each quarter to enable it to pay the minimum quarterly
distribution or any distributions to us. The amount of cash the
nitrogen fertilizer business can distribute on its units
principally depends on the amount of cash it generates from its
operations, which is primarily dependent upon the nitrogen
fertilizer business selling quantities of nitrogen fertilizer at
margins that are high enough to cover its fixed and variable
expenses. The nitrogen fertilizer business costs, the
prices it charges its customers, its level of production and,
accordingly, the cash it generates from operations, will
fluctuate from quarter to quarter based on, among other things,
overall demand for its nitrogen fertilizer products, the level
of foreign and
57
domestic production of nitrogen fertilizer products by others,
the extent of government regulation and overall economic and
local market conditions. In addition:
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The managing general partner of the nitrogen fertilizer business
has broad discretion to establish reserves for the prudent
conduct of the nitrogen fertilizer business. The establishment
of those reserves could result in a reduction of the nitrogen
fertilizer business distributions.
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The amount of distributions made by the nitrogen fertilizer
business and the decision to make any distribution are
determined by the managing general partner of the Partnership,
whose interests may be different from ours. The managing general
partner of the Partnership has limited fiduciary and contractual
duties, which may permit it to favor its own interests to our
detriment.
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Although the partnership agreement requires the nitrogen
fertilizer business to distribute its available cash, the
partnership agreement may be amended.
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Any credit facility that the nitrogen fertilizer business enters
into may limit the distributions which the nitrogen fertilizer
business can make. In addition, any credit facility may contain
financial tests and covenants that the nitrogen fertilizer
business must satisfy. Any failure to comply with these tests
and covenants could result in the lenders prohibiting
distributions by the nitrogen fertilizer business.
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The actual amount of cash available for distribution will depend
on numerous factors, some of which are beyond the control of the
nitrogen fertilizer business, including the level of capital
expenditures made by the nitrogen fertilizer business, the
nitrogen fertilizer business debt service requirements,
the cost of acquisitions, if any, fluctuations in its working
capital needs, its ability to borrow funds and access capital
markets, the amount of fees and expenses incurred by the
nitrogen fertilizer business, and restrictions on distributions
and on the ability of the nitrogen fertilizer business to make
working capital and other borrowings for distributions contained
in its credit agreements.
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If we were
deemed an investment company under the Investment Company Act of
1940, applicable restrictions would make it impractical for us
to continue our business as contemplated and could have a
material adverse effect on our business. We may in the future be
required to sell some or all of our partnership interests in
order to avoid being deemed an investment company, and such
sales could result in gains taxable to the
company.
In order not to be regulated as an investment company under the
Investment Company Act of 1940, as amended (the 1940
Act), unless we can qualify for an exemption, we must
ensure that we are engaged primarily in a business other than
investing, reinvesting, owning, holding or trading in securities
(as defined in the 1940 Act) and that we do not own or acquire
investment securities having a value exceeding 40%
of the value of our total assets (exclusive of
U.S. government securities and cash items) on an
unconsolidated basis. We believe that we are not currently an
investment company because our general partner interests in the
Partnership should not be considered to be securities under the
1940 Act and, in any event, both our refinery business and the
nitrogen fertilizer business are operated through majority-owned
subsidiaries. In addition, even if our general partner interests
in the Partnership were considered securities or investment
securities, we believe that they do not currently have a value
exceeding 40% of the fair market value of our total assets on an
unconsolidated basis.
However, there is a risk that we could be deemed an investment
company if the SEC or a court determines that our general
partner interests in the Partnership are securities or
investment securities under the 1940 Act and if our Partnership
interests constituted more than 40% of the value of our total
assets. Currently, our interests in the Partnership constitute
less than 40% of our total assets on an unconsolidated basis,
but they could constitute a higher percentage of the fair market
value of our
58
total assets in the future if the value of our Partnership
interests increases, the value of our other assets decreases, or
some combination thereof occurs.
We intend to conduct our operations so that we will not be
deemed an investment company. However, if we were deemed an
investment company, restrictions imposed by the 1940 Act,
including limitations on our capital structure and our ability
to transact with affiliates, could make it impractical for us to
continue our business as contemplated and could have a material
adverse effect on our business and the price of our common
stock. In order to avoid registration as an investment company
under the 1940 Act, we may have to sell some or all of our
interests in the Partnership at a time or price we would not
otherwise have chosen. The gain on such sale would be taxable to
us. We may also choose to seek to acquire additional assets that
may not be deemed investment securities, although such assets
may not be available at favorable prices. Under the 1940 Act, we
may have only up to one year to take any such actions.
Use of the
limited partnership structure involves tax risks. For example,
the Partnerships tax treatment depends on its status as a
partnership for federal income tax purposes, as well as it not
being subject to a material amount of entity-level taxation by
individual states. If the IRS were to treat the Partnership as a
corporation for federal income tax purposes or if the
Partnership were to become subject to additional amounts of
entity-level taxation for state tax purposes, then its cash
available for distribution to us would be substantially
reduced.
The anticipated after-tax economic benefit of the
Partnerships master limited partnership structure depends
largely on its being treated as a partnership for U.S. federal
income tax purposes. Despite the fact that the Partnership is
organized as a limited partnership under Delaware law, it is
possible in certain circumstances for a partnership such as the
Partnership to be treated as a corporation for U.S. federal
income tax purposes. If the Partnership proceeds with an initial
public offering, current law would require the Partnership to
derive at least 90% of its annual gross income for the taxable
year of such offering, and in each taxable year thereafter, from
specific activities to continue to be treated as a partnership
for U.S. federal income tax purposes. The Partnership may find
it impossible to meet this 90% qualifying income requirement or
may inadvertently fail to meet such income requirement.
To consummate an initial public offering, the Partnership will
obtain an opinion of legal counsel that, based upon, among other
things, customary representations by the Partnership, the
Partnership will continue to be treated as a partnership for
U.S. federal income tax purposes following such initial public
offering. However, the ability of the Partnership to obtain such
an opinion will depend upon a number of factors, including the
state of the law at the time the Partnership seeks such an
opinion and the specific facts and circumstances of the
Partnership at such time. Therefore, there is no assurance that
the Partnership will be able to obtain such an opinion and,
thus, no assurance that we will be able to realize the
anticipated benefits of the Partnership being a master limited
partnership.
If the Partnership consummates an offering and we sell units, or
our units are redeemed, in a special GP offering, or the
Partnership makes a distribution to us of proceeds of the
offering or debt financing, such sale, redemption or
distribution would likely result in taxable gain to us. We will
also recognize taxable gain to the extent that otherwise
nontaxable distributions exceed our tax basis in the
Partnership. The tax associated with any such taxable gain could
be significant.
If an initial public offering is consummated, a subsequent
change in the Partnerships business could cause the
Partnership to be treated as a corporation for federal income
tax purposes or otherwise subject it to taxation as an entity.
The Partnership is considering, and may consider in the future,
expanding or entering into new activities or businesses. Gross
income from any of these activities or businesses may not count
toward satisfaction of the 90% qualifying income requirement for
the Partnership to be treated as a partnership rather than as a
corporation for U.S. federal income tax purposes.
59
If the Partnership were to be treated as a corporation for U.S.
federal income tax purposes, it would pay U.S. federal income
tax on its income at the corporate tax rate, which is currently
a maximum of 35%, and would pay state income taxes at varying
rates. Because such a tax would be imposed upon the Partnership
as a corporation, the cash available for distribution by the
Partnership to its partners, including us, would be
substantially reduced. In addition, distributions by the
Partnership to us would also be taxable to us (subject to the
70% or 80% dividends received deduction, as applicable,
depending on the degree of ownership we have in the Partnership)
and we would not be able to use our share of any tax losses of
the Partnership to reduce taxes otherwise payable by us. Thus,
treatment of the Partnership as a corporation could result in a
material reduction in our anticipated cash flow and the
after-tax return to us.
In addition, if an initial public offering is consummated, the
law in effect at that time could change so as to cause the
Partnership to be treated as a corporation for U.S. federal
income tax purposes or otherwise subject it to entity-level
taxation. For example, currently, at the federal level,
legislation has been proposed that would eliminate partnership
tax treatment for certain publicly traded partnerships. Although
such legislation as currently proposed would not apply to the
Partnership, it could be amended prior to enactment in a manner
that does apply to the Partnership. At the state level, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise or other forms of taxation. Specifically, beginning in
2008, the Partnership is required to pay Texas franchise tax at
a maximum effective rate of 0.7% of its gross income apportioned
to Texas in the prior year. Imposition of this tax by Texas and,
if applicable, by any other state will reduce the
Partnerships cash available for distribution by the
Partnership. We are unable to predict whether any of these
changes or other proposals will ultimately be enacted. Any such
changes could result in a material reduction in our anticipated
cash flow and the after-tax return to us.
In addition, the sale of the managing general partner interest
of the Partnership to an entity controlled by the Goldman Sachs
Funds and the Kelso Funds was made at the fair market value of
such general partner interest as of the date of transfer, as
determined by our board of directors after consultation with
management. Any gain on this sale by us is subject to tax. If
the IRS or another taxing authority successfully asserted that
the fair market value at the time of sale of the managing
general partner interest exceeded the sale price, we would have
additional deemed taxable income which could reduce our cash
flow and adversely affect our financial results. For example, if
the value of the managing general partner interest increases
over time, possibly significantly because the Partnership
performs well, then in hindsight the sale price might be
challenged or viewed as insufficient by the IRS or another
taxing authority.
Additionally, when the Partnership issues units to new
unitholders or engages in certain other transactions, the
Partnership will determine the fair market value of its assets
and allocate any unrealized gain or loss attributable to those
assets to the capital accounts of the existing partners. As a
result of this revaluation and the Partnerships adoption
of the remedial allocation method under Section 704(c) of
the Internal Revenue Code (i) new unitholders will be
allocated deductions as if the tax basis of the
Partnerships property were equal to the fair market value
thereof at the time of the offering, and (ii) we will be
allocated reverse Section 704(c) allocations of
income or loss over time consistent with our allocation of
unrealized gain or loss.
Fertilizer
GPs interest in the Partnership and the control of
Fertilizer GP may be transferred to a third party without our
consent. the new owners of Fertilizer GP may have no Interest in
CVR Energy and may take actions that are not in our
interest.
Fertilizer GP is currently controlled by the Goldman Sachs Funds
and the Kelso Funds. The Goldman Sachs Funds and the Kelso Funds
will also collectively beneficially own approximately 61.4% of
our common stock following the completion of this offering
(59.7% if the underwriters exercise their option to purchase
additional shares in full). Fertilizer GP may transfer its
managing general partner interest in the Partnership to a third
party in a merger or in a sale of all or substantially all of
its assets without our consent. Furthermore, there is no
restriction in the partnership agreement
60
on the ability of the current owners of Fertilizer GP to
transfer their equity interest in Fertilizer GP to a third
party. The new equity owner of Fertilizer GP would then be in a
position to replace the board of directors (other than the two
directors appointed by us) and the officers of Fertilizer GP
(subject to our joint rights in relation to the chief executive
officer and chief financial officer) with its own choices and to
influence the decisions taken by the board of directors and
officers of Fertilizer GP. These new equity owners, directors
and executive officers may take actions, subject to the
specified joint management rights we have as a holder of special
GP rights, which are not in our interests or the interests of
our stockholders. In particular, the new owners may have no
economic interest in us (unlike the current owners of Fertilizer
GP), which may make it more likely that they would take actions
to benefit Fertilizer GP and its managing general partner
interest over us and our interests in the Partnership.
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CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements. We claim
the protection of the safe harbor for forward-looking statements
provided in the Private Securities Litigation Reform Act of
1995, Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Exchange Act. Statements
that are predictive in nature, that depend upon or refer to
future events or conditions or that include the words
believe, expect, anticipate,
intend, estimate and other expressions
that are predictions of or indicate future events and trends and
that do not relate to historical matters identify
forward-looking statements. Our forward-looking statements
include statements about our business strategy, our industry,
our future profitability, our expected capital expenditures and
the impact of such expenditures on our performance, the costs of
operating as a public company, our capital programs and
environmental expenditures. These statements involve known and
unknown risks, uncertainties and other factors, including the
factors described under Risk Factors, that may cause
our actual results and performance to be materially different
from any future results or performance expressed or implied by
these forward-looking statements. Such risks and uncertainties
include, among other things:
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volatile margins in the refining industry;
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exposure to the risks associated with volatile crude prices;
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the availability of adequate cash and other sources of liquidity
for our capital needs;
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disruption of our ability to obtain an adequate supply of crude
oil;
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losses due to the Cash Flow Swap;
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decreases in the light/heavy
and/or
the
sweet/sour crude oil price spreads;
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losses, damages and lawsuits related to the flood and crude oil
discharge;
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the failure of our new and redesigned equipment in our
facilities to perform according to expectations;
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interruption of the pipelines supplying feedstock and in the
distribution of our products;
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the seasonal nature of our petroleum business;
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competition in the petroleum and nitrogen fertilizer businesses;
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capital expenditures required by environmental laws and
regulations;
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changes in our credit profile;
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the potential decline in the price of natural gas, which
historically has correlated with the market price for nitrogen
fertilizer products;
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the cyclical nature of the nitrogen fertilizer business;
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adverse weather conditions, including potential floods;
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the supply and price levels of essential raw materials;
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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;
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the dependence of the nitrogen fertilizer operations on a few
third-party suppliers;
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the reliance of the nitrogen fertilizer business on third-party
providers of transportation services and equipment;
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environmental laws and regulations affecting the end-use and
application of fertilizers;
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a decrease in ethanol production;
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the potential loss of the nitrogen fertilizer business
transportation cost advantage over its competitors;
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refinery operating hazards and interruptions, including
unscheduled maintenance or downtime, and the availability of
adequate insurance coverage;
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our commodity derivative activities;
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uncertainty regarding our ability to recover costs and losses
resulting from the flood and crude oil discharge;
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our limited operating history as a stand-alone company;
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our dependence on significant customers;
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our potential inability to successfully implement our business
strategies, including the completion of significant capital
programs;
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the success of our acquisition and expansion strategies;
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the dependence on our subsidiaries for cash to meet our debt
obligations;
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our significant indebtedness;
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whether we will be able to amend our credit facility on
acceptable terms if the Partnership seeks to consummate a public
or private offering;
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the potential loss of key personnel;
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labor disputes and adverse employee relations;
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potential increases in costs and distraction of management
resulting from the requirements of being a public company;
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risks relating to evaluations of internal controls required by
Section 404 of the Sarbanes-Oxley Act;
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the operation of our company as a controlled company;
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new regulations concerning the transportation of hazardous
chemicals, risks of terrorism and the security of chemical
manufacturing facilities;
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successfully defending against third-party claims of
intellectual property infringement;
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our ability to continue to license the technology used in our
operations;
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the Partnerships ability to make distributions equal to
the minimum quarterly distribution or any distributions at all;
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the possibility that Partnership distributions to us will
decrease if the Partnership issues additional equity interests
and that our rights to receive distributions will be
subordinated to the rights of third party investors;
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the possibility that we will be required to deconsolidate the
Partnership from our financial statements in the future;
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the Partnerships preferential right to pursue certain
business opportunities before we pursue them;
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reduction of our voting power in the Partnership if the
Partnership completes a public offering or private placement;
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whether we will be required to purchase the managing general
partner interest in the Partnership, and whether we will have
the requisite funds to do so;
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the possibility that we will be required to sell a portion of
our interests in the Partnership in the Partnerships
initial offering at an undesirable time or price;
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the ability of the Partnership to manage the nitrogen fertilizer
business in a manner adverse to our interests;
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the conflicts of interest faced by our senior management, which
operates both our company and the Partnership, and our
controlling stockholders, who control our company and the
managing general partner of the Partnership;
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limitations on the fiduciary duties owed by the managing general
partner which are included in the partnership agreement;
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whether we are ever deemed to be an investment company under the
1940 Act or will need to take actions to sell interests in the
Partnership or buy assets to refrain from being deemed an
investment company;
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changes in the treatment of the Partnership as a partnership for
U.S. income tax purposes;
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|
|
transfer of control of the managing general partner of the
Partnership to a third party that may have no economic interest
in us; and
|
|
|
|
the risk that the Partnership will not consummate a public
offering or private placement.
|
You should not place undue reliance on our forward-looking
statements. Although forward-looking statements reflect our good
faith beliefs, reliance should not be placed on forward-looking
statements because they involve known and unknown risks,
uncertainties and other factors, which may cause our actual
results, performance or achievements to differ materially from
anticipated future results, performance or achievements
expressed or implied by such forward-looking statements. We
undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new
information, future events, changed circumstances or otherwise.
64
USE OF
PROCEEDS
We will not receive any of the proceeds from sale of shares of
our common stock by the selling stockholders. Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC intend
to distribute the net proceeds, after giving effect to the
underwriting discount, from the sale of shares of our common
stock to their members, which includes certain members of our
senior management team. See Principal and Selling
Stockholders.
65
DIVIDEND
POLICY
We do not anticipate paying any cash dividends in the
foreseeable future. We currently intend to retain future
earnings from our refinery business, if any, together with any
cash distributions we receive from the Partnership, to finance
operations and the expansion of our business. Any future
determination to pay cash dividends will be at the discretion of
our board of directors and will be dependent upon our financial
condition, results of operations, capital requirements and other
factors that the board deems relevant. In addition, the
covenants contained in our credit facility limit the ability of
our subsidiaries to pay dividends to us, which limits our
ability to pay dividends to our stockholders, including any
amounts received from the Partnership in the form of quarterly
distributions. Our ability to pay dividends also may be limited
by covenants in other instruments governing future indebtedness
that we or our subsidiaries may incur in the future. See
Description of Our Indebtedness and the Cash Flow
Swap.
In addition, the partnership agreement which governs the
Partnership includes restrictions on the Partnerships
ability to make distributions to us. If the Partnership issues
limited partner interests to third party investors, these
investors will have rights to receive distributions which, in
some cases, will be senior to our rights to receive
distributions. In addition, the managing general partner of the
Partnership has incentive distribution rights which, over time,
will give it rights to receive distributions. These provisions
will limit the amount of distributions which the Partnership can
make to us which will, in turn, limit our ability to make
distributions to our stockholders. In addition, since the
Partnership will make its distributions to Coffeyville
Resources, LLC, a subsidiary of ours, our credit facility will
limit the ability of Coffeyville Resources, LLC to distribute
these distributions to us. In addition, the Partnership may also
enter into its own credit facility or other contracts that limit
its ability to make distributions to us.
In October 2007, the directors of Coffeyville Acquisition LLC
and Coffeyville Acquisition II LLC, respectively, approved
a special dividend of $10.6 million to their members,
including approximately $5.2 million to the Goldman Sachs
Funds, approximately $5.1 million to the Kelso Funds and
approximately $0.3 million to certain members of our senior
management team, a director and an unrelated member. The common
unit holders receiving this special dividend contributed
$10.6 million collectively to Coffeyville
Acquisition III LLC, which used such amounts to purchase
the managing general partner of the Partnership.
66
MARKET PRICE OF
OUR COMMON STOCK
Our common stock has been listed on the New York Stock Exchange
under the symbol CVI since October 23, 2007.
Prior to that time, there was no public market for our common
stock. The following table sets forth for the periods indicated
the high and low reported sale prices per share of our common
stock on the New York Stock Exchange. These prices do not
include retail markups, markdowns or commissions.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
Fourth Quarter (from October 23, 2007)
|
|
$
|
26.25
|
|
|
$
|
19.80
|
|
Year Ending December 31, 2008:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
30.94
|
|
|
|
20.71
|
|
Second Quarter (through June 17, 2008)
|
|
|
28.88
|
|
|
|
19.57
|
|
A recent reported closing price for our common stock is set
forth on the cover page of this prospectus. American Stock
Transfer & Trust Company is the registrar and
transfer agent for our common stock. We estimate that there were
approximately 451 holders of record of our common stock as
of June 16, 2008. Because many of our shares of common
stock are held by brokers and other institutions on behalf of
stockholders, we are unable to estimate the total number of
stockholders represented by these record holders.
67
CAPITALIZATION
The following table sets forth our consolidated cash and cash
equivalents and capitalization as of March 31, 2008:
|
|
|
|
|
on an actual basis;
|
|
|
|
on an adjusted basis to give effect to (a) the proposed
$25.0 million senior secured credit facility,
(b) certain expenses associated with this offering and
(c) the Phantom Unit Plans payment of $3.5 million
(assuming the underwriters option is not exercised) by us
to members of our senior management team as a result of this
offering, as if each had occurred on March 31,
2008; and
|
|
|
|
on an as further adjusted basis to give effect to (a), (b) and
(c) above as well as (d) our concurrent offering of
$125.0 million aggregate principal amount of our
Convertible Senior Notes due 2013 (assuming the
underwriters option is not exercised), as if each had
occurred on March 31, 2008. The consummation of this equity
offering is not conditioned upon the consummation of our
concurrent offering of Convertible Senior Notes due 2013 and
vice versa.
|
You should read this table in conjunction with Selected
Historical Consolidated Financial Data,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, and the consolidated
financial statements and related notes included elsewhere in
this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2008
|
|
|
|
|
|
|
|
|
|
Further
|
|
|
|
|
|
|
|
|
|
Adjusted for
|
|
|
|
|
|
|
|
|
|
Convertible
|
|
|
|
Actual
|
|
|
As Adjusted
|
|
|
Offering
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
25,179
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (including current portion):
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility(1)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Term loan facility
|
|
|
487,979
|
|
|
|
|
|
|
|
|
|
Proposed senior secured credit facility
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible senior notes due 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
487,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in subsidiaries(2)
|
|
|
10,600
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value per share,
350,000,000 shares authorized; 86,141,291 shares
issued and outstanding
|
|
|
861
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value per share,
50,000,000 shares authorized; no shares issued and
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
458,523
|
|
|
|
|
|
|
|
|
|
Retained earning (deficit)
|
|
|
(4,279
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
455,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
953,684
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As of June 16, 2008, we had availability of
$112.6 million under our revolving credit facility.
|
|
(2)
|
|
Represents the managing general partners interest in the
Partnership held by Coffeyville Acquisition III LLC.
|
68
SELECTED
HISTORICAL CONSOLIDATED FINANCIAL DATA
The historical data presented below has been derived from
financial statements that have been prepared using GAAP and that
are included elsewhere in this prospectus. You should read the
selected historical consolidated financial data presented below
in conjunction with Managements Discussion and
Analysis of Financial Condition and Results of Operations
and our consolidated financial statements and the related notes
included elsewhere in this prospectus.
The selected consolidated financial information presented below
under the caption Statement of Operations Data for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005 and the years ended
December 31, 2006 and 2007 and the selected consolidated
financial information presented below under the caption Balance
Sheet Data as of December 31, 2006 and 2007 has been
derived from our audited consolidated financial statements
included elsewhere in this prospectus, which financial
statements have been audited by KPMG LLP, independent registered
public accounting firm. The consolidated financial information
presented below under the caption Statement of Operations Data
for the year ended December 31, 2003, the
62-day
period ended March 2, 2004 and the 304 days ended
December 31, 2004, and the consolidated financial
information presented below under the caption Balance Sheet Data
at December 31, 2003, 2004 and 2005, are derived from our
audited consolidated financial statements that are not included
in this prospectus. The selected unaudited interim consolidated
financial information presented below under the caption
Statement of Operations Data presented below for the three month
period ended March 31, 2007 and the three month period
ended March 31, 2008, and the selected unaudited interim
consolidated financial information presented below under the
caption Balance Sheet Data as of March 31, 2008, have been
derived from our unaudited interim consolidated financial
statements, which are included elsewhere in this prospectus and
have been prepared on the same basis as the audited consolidated
financial statements. In the opinion of management, the interim
data reflect all adjustments, consisting only of normal and
recurring adjustments, necessary for a fair presentation of
results for these periods. Operating results for the three month
period ended March 31, 2008 are not necessarily indicative
of the results that may be expected for the year ending
December 31, 2008.
Prior to March 3, 2004, our assets were operated as a
component of Farmland. We refer to our operations as part of
Farmland during this period as Original Predecessor.
Farmland filed for bankruptcy protection under Chapter 11
of the U.S. Bankruptcy Code on May 31, 2002. On
March 3, 2004, Coffeyville Resources, LLC completed the
purchase of Original Predecessor from Farmland in a sales
process under Chapter 11 of the U.S. Bankruptcy Code.
See Note 1 to our consolidated financial statements
included elsewhere in this prospectus. We refer to this
acquisition as the Initial Acquisition, and we refer to our
post-Farmland operations run by Coffeyville Group Holdings, LLC
as Immediate Predecessor. Our business was operated by the
Immediate Predecessor for the 304 days ended
December 31, 2004 and the 174 days ended June 23,
2005. As a result of certain adjustments made in connection with
the Initial Acquisition, a new basis of accounting was
established on the date of the Initial Acquisition and the
results of operations for the 304 days ended
December 31, 2004 are not comparable to prior periods.
During periods when we were operated as part of Farmland, which
include the fiscal year ended December 31, 2003 and the
62 days ended March 2, 2004, Farmland allocated
certain general corporate expenses and interest expense to
Original Predecessor. The allocation of these costs is not
necessarily indicative of the costs that would have been
incurred if Original Predecessor had operated as a stand-alone
entity. Further, the historical results are not necessarily
indicative of the results to be expected in future periods.
We calculate earnings per share for the years ended
December 31, 2006 and 2007 and the three month period ended
March 31, 2007 on a pro forma basis, assuming our post-IPO
capital structure had been in place for the entire year for each
of 2006 and 2007. For the year ended December 31, 2007,
17,500 non-vested common shares and 18,900 common stock options
have been excluded from the calculation of pro forma diluted
earnings per share because the inclusion of such common stock
equivalents in the number of weighted average shares outstanding
would be anti-dilutive. We have omitted earnings per share data
for Immediate Predecessor because we operated
69
under a different capital structure than our current capital
structure and, therefore, the information is not meaningful.
We have omitted per share data for Original Predecessor because,
under Farmlands cooperative structure, earnings of
Original Predecessor were distributed as patronage dividends to
members and associate members based on the level of business
conducted with Original Predecessor as opposed to a common
stockholders proportionate share of underlying equity in
Original Predecessor.
Original Predecessor was not a separate legal entity, and its
operating results were included with the operating results of
Farmland and its subsidiaries in filing consolidated federal and
state income tax returns. As a cooperative, Farmland was subject
to income taxes on all income not distributed to patrons as
qualifying patronage refunds and Farmland did not allocate
income taxes to its divisions. As a result, Original Predecessor
periods do not reflect any provision for income taxes.
On June 24, 2005, pursuant to a stock purchase agreement
dated May 15, 2005, Coffeyville Acquisition LLC acquired
all of the subsidiaries of Coffeyville Group Holdings, LLC. See
Note 1 to our consolidated financial statements included
elsewhere in this prospectus. We refer to this acquisition as
the Subsequent Acquisition, and we refer to our
post-June 24, 2005 operations as Successor. As a result of
certain adjustments made in connection with the Subsequent
Acquisition, a new basis of accounting was established on the
date of the acquisition. Since the assets and liabilities of
Successor and Immediate Predecessor were each presented on a new
basis of accounting, the financial information for Successor,
Immediate Predecessor and Original Predecessor is not comparable.
Financial data for the 2005 fiscal year is presented as the
174 days ended June 23, 2005 and the 233 days
ended December 31, 2005. Successor had no financial
statement activity during the period from May 13, 2005 to
June 24, 2005, with the exception of certain crude oil,
heating oil, and gasoline option agreements entered into with a
related party as of May 16, 2005.
On April 23, 2008, the audit committee of our board of
directors and management concluded that our previously issued
consolidated financial statements for the year ended
December 31, 2007 and the related quarter ended
September 30, 2007 contained errors. See footnote 2 to our
consolidated financial statements for the year ended
December 31, 2007 included elsewhere in this prospectus and
Managements Discussion and Analysis of Financial
Condition and Results of Operations Restatement of
Year Ended December 31, 2007 and Quarter Ended September
30, 2007 Financial Statements. All information presented
in this prospectus reflects our restated financial results.
70
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
March 31, 2007
|
|
|
March 31, 2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions, unless
|
|
|
|
otherwise indicated)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
390.5
|
|
|
$
|
1,223.0
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
303.7
|
|
|
|
1,036.2
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
113.4
|
|
|
|
60.6
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
13.2
|
|
|
|
13.4
|
|
Net costs associated with flood(1)
|
|
|
|
|
|
|
5.8
|
|
Depreciation and amortization(2)
|
|
|
14.2
|
|
|
|
19.6
|
|
Operating income (loss)
|
|
|
(54.0
|
)
|
|
|
87.4
|
|
Other income, net
|
|
|
0.5
|
|
|
|
0.9
|
|
Interest expense and other financing costs
|
|
|
(11.9
|
)
|
|
|
(11.3
|
)
|
Loss on derivatives, net
|
|
|
(137.0
|
)
|
|
|
(47.9
|
)
|
Income (loss) before income taxes and minority interests in
subsidiaries
|
|
|
(202.4
|
)
|
|
|
29.1
|
|
Income tax (expense) benefit
|
|
|
(47.3
|
)
|
|
|
(6.9
|
)
|
Minority interest in (income) loss of subsidiaries
|
|
|
0.7
|
|
|
|
|
|
Net income (loss)(3)
|
|
|
(154.4
|
)
|
|
|
22.2
|
|
Pro forma earnings (loss) per share, basic
|
|
|
(1.79
|
)
|
|
|
|
|
Pro forma earnings (loss) per share, diluted
|
|
|
(1.79
|
)
|
|
|
|
|
Pro forma weighted average shares, basic
|
|
|
86,141,291
|
|
|
|
|
|
Pro forma weighted average shares, diluted
|
|
|
86,141,291
|
|
|
|
|
|
Earnings per share, basic
|
|
|
|
|
|
|
0.26
|
|
Earnings per share, diluted
|
|
|
|
|
|
|
0.26
|
|
Weighted average shares, basic
|
|
|
|
|
|
|
86,141,291
|
|
Weighted average shares, diluted
|
|
|
|
|
|
|
86,158,791
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
|
|
|
25.2
|
|
Working capital
|
|
|
|
|
|
|
21.5
|
|
Total assets
|
|
|
|
|
|
|
1,923.6
|
|
Total debt, including current portion
|
|
|
|
|
|
|
499.2
|
|
Minority interest in subsidiaries
|
|
|
|
|
|
|
10.6
|
|
Stockholders equity
|
|
|
|
|
|
|
455.1
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
Depreciation and amortization(2)
|
|
|
14.2
|
|
|
|
19.6
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(4)
|
|
|
(82.4
|
)
|
|
|
30.6
|
|
Cash flows provided by operating activities
|
|
|
44.1
|
|
|
|
24.2
|
|
Cash flows (used in) investing activities
|
|
|
(107.4
|
)
|
|
|
(26.2
|
)
|
Cash flows provided by (used in) financing activities
|
|
|
29.0
|
|
|
|
(3.4
|
)
|
Capital expenditures for property, plant and equipment
|
|
|
107.4
|
|
|
|
26.2
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
Production (barrels per day)(5)
|
|
|
53,689
|
|
|
|
125,614
|
|
Crude oil throughput (barrels per day)(5)
|
|
|
47,267
|
|
|
|
106,530
|
|
Refining margin per crude oil throughput barrel (dollars)(6)
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
NYMEX 2-1-1 crack spread (dollars)(7)
|
|
$
|
12.17
|
|
|
$
|
11.81
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)(8)
|
|
$
|
22.73
|
|
|
$
|
4.16
|
|
Gross profit (loss) per crude oil throughput per barrel
(dollars)(8)
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)
|
|
|
86.2
|
|
|
|
83.7
|
|
UAN (tons in thousands)
|
|
|
165.7
|
|
|
|
150.1
|
|
On-stream factors:
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
91.8
|
%
|
|
|
91.8
|
%
|
Ammonia
|
|
|
86.3
|
%
|
|
|
90.7
|
%
|
UAN
|
|
|
89.4
|
%
|
|
|
85.9
|
%
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Original Predecessor
|
|
|
Immediate Predecessor
|
|
|
Successor
|
|
|
|
Year
|
|
|
62 Days
|
|
|
304 Days
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
June 23,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
(in millions, unless otherwise indicated)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
1,262.2
|
|
|
$
|
261.1
|
|
|
$
|
1,479.9
|
|
|
$
|
980.7
|
|
|
$
|
1,454.3
|
|
|
$
|
3,037.6
|
|
|
$
|
2,966.9
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
1,061.9
|
|
|
|
221.4
|
|
|
|
1,244.2
|
|
|
|
768.0
|
|
|
|
1,168.1
|
|
|
|
2,443.4
|
|
|
|
2,308.8
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
133.1
|
|
|
|
23.4
|
|
|
|
117.0
|
|
|
|
80.9
|
|
|
|
85.3
|
|
|
|
199.0
|
|
|
|
276.1
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
23.6
|
|
|
|
4.7
|
|
|
|
16.3
|
|
|
|
18.4
|
|
|
|
18.4
|
|
|
|
62.6
|
|
|
|
93.1
|
|
Net costs associated with flood(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41.5
|
|
Depreciation and amortization(2)
|
|
|
3.3
|
|
|
|
0.4
|
|
|
|
2.4
|
|
|
|
1.1
|
|
|
|
24.0
|
|
|
|
51.0
|
|
|
|
60.8
|
|
Impairment, earnings (losses) in joint ventures, and other
charges(9)
|
|
|
10.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
29.4
|
|
|
$
|
11.2
|
|
|
$
|
100.0
|
|
|
$
|
112.3
|
|
|
$
|
158.5
|
|
|
$
|
281.6
|
|
|
$
|
186.6
|
|
Other income (expense)(10)
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
(6.9
|
)
|
|
|
(8.4
|
)
|
|
|
0.4
|
|
|
|
(20.8
|
)
|
|
|
0.2
|
|
Interest (expense)
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
(10.1
|
)
|
|
|
(7.8
|
)
|
|
|
(25.0
|
)
|
|
|
(43.9
|
)
|
|
|
(61.1
|
)
|
Gain (loss) on derivatives
|
|
|
0.3
|
|
|
|
|
|
|
|
0.5
|
|
|
|
(7.6
|
)
|
|
|
(316.1
|
)
|
|
|
94.5
|
|
|
|
(282.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
$
|
27.9
|
|
|
$
|
11.2
|
|
|
$
|
83.5
|
|
|
$
|
88.5
|
|
|
$
|
(182.2
|
)
|
|
$
|
311.4
|
|
|
$
|
(156.3
|
)
|
Income tax (expense) benefit
|
|
|
|
|
|
|
|
|
|
|
(33.8
|
)
|
|
|
(36.1
|
)
|
|
|
63.0
|
|
|
|
(119.8
|
)
|
|
|
88.5
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(3)
|
|
$
|
27.9
|
|
|
$
|
11.2
|
|
|
$
|
49.7
|
|
|
$
|
52.4
|
|
|
$
|
(119.2
|
)
|
|
$
|
191.6
|
|
|
$
|
(67.6
|
)
|
Pro forma earnings per share, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Pro forma earnings per share, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Pro forma weighted average shares, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Pro forma weighted average shares, diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
Historical dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred per unit(11)
|
|
|
|
|
|
|
|
|
|
$
|
1.50
|
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common per unit(11)
|
|
|
|
|
|
|
|
|
|
$
|
0.48
|
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management common units subject to redemption
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3.1
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
246.9
|
|
|
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
0.0
|
|
|
|
|
|
|
$
|
52.7
|
|
|
|
|
|
|
$
|
64.7
|
|
|
$
|
41.9
|
|
|
$
|
30.5
|
|
Working capital(12)
|
|
|
150.5
|
|
|
|
|
|
|
|
106.6
|
|
|
|
|
|
|
|
108.0
|
|
|
|
112.3
|
|
|
|
10.7
|
|
Total assets
|
|
|
199.0
|
|
|
|
|
|
|
|
229.2
|
|
|
|
|
|
|
|
1,221.5
|
|
|
|
1,449.5
|
|
|
|
1,868.4
|
|
Liabilities subject to compromise(13)
|
|
|
105.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt, including current portion
|
|
|
|
|
|
|
|
|
|
|
148.9
|
|
|
|
|
|
|
|
499.4
|
|
|
|
775.0
|
|
|
|
500.8
|
|
Minority interest in subsidiaries(14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
|
|
10.6
|
|
Management units subject to redemption
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.7
|
|
|
|
7.0
|
|
|
|
|
|
Divisional/members/stockholders equity
|
|
|
58.2
|
|
|
|
|
|
|
|
14.1
|
|
|
|
|
|
|
|
115.8
|
|
|
|
76.4
|
|
|
|
432.7
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
3.3
|
|
|
$
|
0.4
|
|
|
$
|
2.4
|
|
|
$
|
1.1
|
|
|
$
|
24.0
|
|
|
$
|
51.0
|
|
|
$
|
68.4
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(4)
|
|
|
27.9
|
|
|
|
11.2
|
|
|
|
49.7
|
|
|
|
52.4
|
|
|
|
23.6
|
|
|
|
115.4
|
|
|
|
(5.6
|
)
|
Cash flows provided by operating activities
|
|
|
20.3
|
|
|
|
53.2
|
|
|
|
89.8
|
|
|
|
12.7
|
|
|
|
82.5
|
|
|
|
186.6
|
|
|
|
145.9
|
|
Cash flows (used in) investing activities
|
|
|
(0.8
|
)
|
|
|
|
|
|
|
(130.8
|
)
|
|
|
(12.3
|
)
|
|
|
(730.3
|
)
|
|
|
(240.2
|
)
|
|
|
(268.6
|
)
|
Cash flows provided by (used in) financing activities
|
|
|
(19.5
|
)
|
|
|
(53.2
|
)
|
|
|
93.6
|
|
|
|
(52.4
|
)
|
|
|
712.5
|
|
|
|
30.8
|
|
|
|
111.3
|
|
Capital expenditures for property, plant and equipment
|
|
|
0.8
|
|
|
|
|
|
|
|
14.2
|
|
|
|
12.3
|
|
|
|
45.2
|
|
|
|
240.2
|
|
|
|
268.6
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (barrels per day)(5)(15)
|
|
|
95,701
|
|
|
|
106,645
|
|
|
|
102,046
|
|
|
|
99,171
|
|
|
|
107,177
|
|
|
|
108,031
|
|
|
|
86,201
|
|
Crude oil throughput (barrels per day)(5)(15)
|
|
|
85,501
|
|
|
|
92,596
|
|
|
|
90,418
|
|
|
|
88,012
|
|
|
|
93,908
|
|
|
|
94,524
|
|
|
|
76,285
|
|
Refining margin per crude oil throughput barrel (dollars)(6)
|
|
$
|
3.89
|
|
|
$
|
4.23
|
|
|
$
|
5.92
|
|
|
$
|
9.28
|
|
|
$
|
11.55
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
NYMEX 2-1-1 crack spread (dollars)(7)
|
|
$
|
5.53
|
|
|
$
|
6.80
|
|
|
$
|
7.55
|
|
|
$
|
9.60
|
|
|
$
|
13.47
|
|
|
$
|
10.84
|
|
|
$
|
13.95
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)(8)
|
|
$
|
2.57
|
|
|
$
|
2.60
|
|
|
$
|
2.66
|
|
|
$
|
3.44
|
|
|
$
|
3.13
|
|
|
$
|
3.92
|
|
|
$
|
7.52
|
|
Gross profit (loss) per crude oil throughput per barrel
(dollars)(8)
|
|
$
|
1.25
|
|
|
$
|
1.57
|
|
|
$
|
3.20
|
|
|
$
|
5.79
|
|
|
$
|
7.55
|
|
|
$
|
8.39
|
|
|
$
|
7.79
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)(15)
|
|
|
335.7
|
|
|
|
56.4
|
|
|
|
252.8
|
|
|
|
193.2
|
|
|
|
220.0
|
|
|
|
369.3
|
|
|
|
326.7
|
|
UAN (tons in thousands)(15)
|
|
|
510.6
|
|
|
|
93.4
|
|
|
|
439.2
|
|
|
|
309.9
|
|
|
|
353.4
|
|
|
|
633.1
|
|
|
|
576.9
|
|
On-steam factors (16):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasifier
|
|
|
90.1
|
%
|
|
|
93.5
|
%
|
|
|
92.2
|
%
|
|
|
97.4
|
%
|
|
|
98.7
|
%
|
|
|
92.5
|
%
|
|
|
90.0
|
%
|
Ammonia
|
|
|
89.6
|
%
|
|
|
80.9
|
%
|
|
|
79.7
|
%
|
|
|
95.0
|
%
|
|
|
98.3
|
%
|
|
|
89.3
|
%
|
|
|
87.7
|
%
|
UAN
|
|
|
81.6
|
%
|
|
|
88.7
|
%
|
|
|
82.2
|
%
|
|
|
93.9
|
%
|
|
|
94.8
|
%
|
|
|
88.9
|
%
|
|
|
78.7
|
%
|
|
|
|
(1)
|
|
Represents the write-off of
approximate net costs associated with the flood and crude oil
spill that are not probable of recovery. See Flood and
Crude Oil Discharge.
|
(2)
|
|
Depreciation and amortization is
comprised of the following components as excluded from cost of
product sold, direct operating expenses and selling, general and
administrative expenses:
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Original Predecessor
|
|
|
Immediate Predecessor
|
|
|
Successor
|
|
|
|
Year
|
|
|
62 Days
|
|
|
304 Days
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Year
|
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
June 23,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
|
|
Depreciation and amortization included in cost of product sold
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.2
|
|
|
$
|
0.1
|
|
|
$
|
1.1
|
|
|
$
|
2.2
|
|
|
$
|
2.4
|
|
|
|
$
|
0.6
|
|
|
$
|
0.6
|
|
Depreciation and amortization included in direct operating
expense
|
|
|
3.3
|
|
|
|
0.4
|
|
|
|
2.2
|
|
|
|
0.9
|
|
|
|
22.7
|
|
|
|
47.7
|
|
|
|
57.4
|
|
|
|
|
13.5
|
|
|
|
18.7
|
|
Depreciation and amortization included in selling, general and
administrative expense
|
|
|
|
|
|
|
|
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
1.1
|
|
|
|
1.0
|
|
|
|
|
0.1
|
|
|
|
0.3
|
|
Depreciation and amortization included in net costs associated
with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
3.3
|
|
|
$
|
0.4
|
|
|
$
|
2.4
|
|
|
$
|
1.1
|
|
|
$
|
24.0
|
|
|
$
|
51.0
|
|
|
$
|
68.4
|
|
|
|
$
|
14.2
|
|
|
$
|
19.6
|
|
|
|
|
(3)
|
|
The following are certain charges
and costs incurred in each of the relevant periods that are
meaningful to understanding our net income and in evaluating our
performance due to their unusual or infrequent nature:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Original Predecessor
|
|
|
Immediate Predecessor
|
|
|
Successor
|
|
|
|
Year
|
|
|
62 Days
|
|
|
304 Days
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Year
|
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
June 23,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
Impairment of property, plant and equipment(a)
|
|
$
|
9.6
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Loss on extinguishment of debt(b)
|
|
|
|
|
|
|
|
|
|
|
7.2
|
|
|
|
8.1
|
|
|
|
|
|
|
|
23.4
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
Inventory fair market value adjustment(c)
|
|
|
|
|
|
|
|
|
|
|
3.0
|
|
|
|
|
|
|
|
16.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded letter of credit expense and interest rate swap not
included in interest expense(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3
|
|
|
|
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
0.9
|
|
Major scheduled turnaround expense(e)
|
|
|
|
|
|
|
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
6.6
|
|
|
|
76.4
|
|
|
|
|
66.0
|
|
|
|
|
|
Loss on termination of swap(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss from Cash Flow Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
235.9
|
|
|
|
(126.8
|
)
|
|
|
103.2
|
|
|
|
|
119.7
|
|
|
|
13.9
|
|
|
|
|
(a)
|
|
During the year ended
December 31, 2003, we recorded a charge of
$9.6 million related to the asset impairment of our
refinery and nitrogen fertilizer plant based on the expected
sales price of the assets in the Initial Acquisition.
|
|
(b)
|
|
Represents the write-off of: (i)
$7.2 million of deferred financing costs in connection with
the refinancing of our senior secured credit facility on
May 10, 2004, (ii) $8.1 million of deferred financing
costs in connection with the refinancing of our senior secured
credit facility on June 23, 2005, (iii) $23.4 million
in connection with the refinancing of our senior secured credit
facility on December 28, 2006 and
(iv) $1.3 million in connection with the repayment and
termination of three credit facilities on October 26, 2007.
|
|
(c)
|
|
Consists of the additional cost of
product sold expense due to the step up to estimated fair value
of certain inventories on hand at March 3, 2004 and
June 24, 2005, as a result of the allocation of the
purchase price of the Initial Acquisition and the Subsequent
Acquisition to inventory.
|
|
(d)
|
|
Consists of fees which are expensed
to selling, general and administrative expenses in connection
with the funded letter of credit facility of $150.0 million
issued in support of the Cash Flow Swap. We consider these fees
to be equivalent to interest expense and the fees are treated as
such in the calculation of EBITDA in the credit facility.
|
|
(e)
|
|
Represents expense associated with
a major scheduled turnaround.
|
|
(f)
|
|
Represents the expense associated
with the expiration of the crude oil, heating oil and gasoline
option agreements entered into by Coffeyville Acquisition LLC in
May 2005.
|
73
|
|
|
(4)
|
|
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap results from
adjusting for the unrealized portion of the derivative
transaction that was executed in conjunction with the
acquisition of Coffeyville Group Holdings, LLC by Coffeyville
Acquisition LLC on June 24, 2005. On June 16, 2005,
Coffeyville Acquisition LLC entered into the Cash Flow Swap with
J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a
related party of ours. The Cash Flow Swap was subsequently
assigned by Coffeyville Acquisition LLC to Coffeyville
Resources, LLC on June 24, 2005. The derivative took the
form of three NYMEX swap agreements whereby if absolute (i.e.,
in dollar terms, not as a percentage of crude oil prices) crack
spreads fall below the fixed level, J. Aron agreed to pay the
difference to us, and if absolute crack spreads rise above the
fixed level, we agreed to pay the difference to J. Aron. Based
upon expected crude oil capacity of 115,000 bpd, the Cash
Flow Swap represents approximately 58% and 14% of crude oil
capacity for the periods July 1, 2008 through June 30,
2009 and July 1, 2009 through June 30, 2010,
respectively. Under the terms of our credit facility and upon
meeting specific requirements related to our leverage ratio and
our credit ratings, we are permitted to reduce the Cash Flow
Swap to 35,000 bpd, or approximately 30% of expected crude
oil capacity, for the period from April 1, 2008 through
December 31, 2008 and terminate the Cash Flow Swap in 2009
and 2010, so long as at the time of reduction or termination, we
pay the amount of unrealized losses associated with the amount
reduced or terminated. See Description of our Indebtedness
and the Cash Flow Swap.
|
We have determined that the Cash Flow Swap does not qualify as a
hedge for hedge accounting purposes under current GAAP. As a
result, our periodic statements of operations reflect in each
period material amounts of unrealized gains and losses based on
the increases or decreases in market value of the unsettled
position under the swap agreements, which is accounted for as a
liability on our balance sheet. As the absolute crack spreads
increase we are required to record an increase in this liability
account with a corresponding expense entry to be made to our
statement of operations. Conversely, as absolute crack spreads
decline we are required to record a decrease in the swap related
liability and post a corresponding income entry to our statement
of operations. Because of this inverse relationship between the
economic outlook for our underlying business (as represented by
crack spread levels) and the income impact of the unrecognized
gains and losses, and given the significant periodic
fluctuations in the amounts of unrealized gains and losses,
management utilizes Net income (loss) adjusted for unrealized
gain or loss from Cash Flow Swap as a key indicator of our
business performance. In managing our business and assessing its
growth and profitability from a strategic and financial planning
perspective, management and our board of directors considers our
GAAP net income results as well as Net income (loss) adjusted
for unrealized gain or loss from Cash Flow Swap. We believe that
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap enhances the understanding of our results of
operations by highlighting income attributable to our ongoing
operating performance exclusive of charges and income resulting
from mark to market adjustments that are not necessarily
indicative of the performance of our underlying business and our
industry. The adjustment has been made for the unrealized loss
from Cash Flow Swap net of its related tax benefit.
|
|
|
|
|
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap is not a recognized
term under GAAP and should not be substituted for net income as
a measure of our performance but instead should be utilized as a
supplemental measure of financial performance or liquidity in
evaluating our business. Because Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap excludes mark to
market adjustments, the measure does not reflect the fair market
value of our Cash Flow Swap in our net income. As a result, the
measure does not include potential cash payments that may be
required to be made on the Cash Flow Swap in the future. Also,
our presentation of this non-GAAP measure may not be comparable
to similarly titled measures of other companies.
|
|
|
|
The following is a reconciliation
of Net income (loss) adjusted for unrealized gain or loss from
Cash Flow Swap to Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Original Predecessor
|
|
|
Immediate Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
62 Days
|
|
|
304 Days
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Ended
|
|
|
|
Three
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
December 31,
|
|
|
|
Months Ended
|
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
June 23,
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
2007
|
|
|
2008
|
|
|
|
(in millions)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Net income (loss) adjusted for unrealized gain (loss) from Cash
Flow Swap
|
|
$
|
27.9
|
|
|
$
|
11.2
|
|
|
$
|
49.7
|
|
|
$
|
52.4
|
|
|
$
|
23.6
|
|
|
$
|
115.4
|
|
|
$
|
(5.6
|
)
|
|
|
$
|
(82.4
|
)
|
|
$
|
30.6
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142.8
|
)
|
|
|
76.2
|
|
|
|
(62.0
|
)
|
|
|
|
(72.0
|
)
|
|
|
(8.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
27.9
|
|
|
$
|
11.2
|
|
|
$
|
49.7
|
|
|
$
|
52.4
|
|
|
$
|
(119.2
|
)
|
|
$
|
191.6
|
|
|
$
|
(67.6
|
)
|
|
|
$
|
(154.4
|
)
|
|
$
|
22.2
|
|
|
|
|
(5)
|
|
Barrels per day is calculated by
dividing the volume in the period by the number of calendar days
in the period. Barrels per day as shown here is impacted by
plant down-time and other plant disruptions and does not
represent the capacity of the facilitys continuous
operations.
|
|
(6)
|
|
Refining margin per crude oil
throughput barrel is a measurement calculated as the difference
between net sales and cost of product sold (exclusive of
depreciation and amortization) divided by the refinerys
crude oil throughput volumes for the respective periods
presented. Refining margin per crude oil throughput barrel is a
non-GAAP measure that should not be substituted for gross profit
or operating income and that we believe is important to
investors in evaluating our refinerys performance as a
general indication of the amount above our cost of product sold
that we are able to sell refined products. Our calculation of
refining margin per crude oil throughput barrel may differ from
similar calculations of other companies in our industry, thereby
limiting its usefulness as a comparative measure. We use
refining margin per crude oil throughput barrel as the most
direct and comparable metric to a crack spread which is an
observable market indication of industry profitability.
|
|
|
|
The table included in footnote 8
reconciles refining margin per crude oil throughput barrel to
gross profit for the periods presented.
|
|
(7)
|
|
This information is industry data
and is not derived from our audited financial statements or
unaudited interim financial statements.
|
74
|
|
|
(8)
|
|
Direct operating expenses
(exclusive of depreciation and amortization) per crude oil
throughput barrel is calculated by dividing direct operating
expenses (exclusive of depreciation and amortization) by total
crude oil throughput volumes for the respective periods
presented. Direct operating expenses (exclusive of depreciation
and amortization) per crude oil throughput barrel includes costs
associated with the actual operations of the refinery, such as
energy and utility costs, catalyst and chemical costs, repairs
and maintenance and labor and environmental compliance costs but
does not include depreciation or amortization. We use direct
operating expenses (exclusive of depreciation and amortization)
per crude oil throughput barrel as a measure of operating
efficiency within the plant and as a control metric for
expenditures.
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel is a non-GAAP
measure. Our calculations of direct operating expenses
(exclusive of depreciation and amortization) per crude oil
throughput barrel may differ from similar calculations of other
companies in our industry, thereby limiting its usefulness as a
comparative measure. The following table reflects direct
operating expenses (exclusive of depreciation and amortization)
and the related calculation of direct operating expenses per
crude oil throughput barrel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
|
Original Predecessor
|
|
|
|
Immediate Predecessor
|
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
|
Three
|
|
|
|
Year
|
|
|
62 Days
|
|
|
|
304 Days
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Months
|
|
|
Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
March 2,
|
|
|
|
December 31,
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
|
2004
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in millions, except as otherwise indicated)
|
|
Petroleum Business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Sales
|
|
$
|
1,161.3
|
|
|
$
|
241.6
|
|
|
|
$
|
1,390.8
|
|
|
$
|
903.8
|
|
|
|
$
|
1,363.4
|
|
|
$
|
2,880.4
|
|
|
$
|
2,806.2
|
|
|
|
$
|
352.5
|
|
|
$
|
1,168.5
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
1,040.0
|
|
|
|
217.4
|
|
|
|
|
1,228.1
|
|
|
|
761.7
|
|
|
|
|
1,156.2
|
|
|
|
2,422.7
|
|
|
|
2,300.2
|
|
|
|
|
298.5
|
|
|
|
1,035.1
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
80.1
|
|
|
|
14.9
|
|
|
|
|
73.2
|
|
|
|
52.6
|
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
|
5.5
|
|
Depreciation and amortization
|
|
|
2.1
|
|
|
|
0.3
|
|
|
|
|
1.5
|
|
|
|
0.8
|
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit (loss)
|
|
$
|
39.1
|
|
|
$
|
9.0
|
|
|
|
$
|
88.0
|
|
|
$
|
88.7
|
|
|
|
$
|
135.4
|
|
|
$
|
289.4
|
|
|
$
|
216.8
|
|
|
|
$
|
(52.5
|
)
|
|
$
|
72.7
|
|
Plus direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
80.1
|
|
|
|
14.9
|
|
|
|
|
73.2
|
|
|
|
52.6
|
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Plus net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
|
5.5
|
|
Plus depreciation and amortization
|
|
|
2.1
|
|
|
|
0.3
|
|
|
|
|
1.5
|
|
|
|
0.8
|
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin
|
|
$
|
121.3
|
|
|
$
|
24.2
|
|
|
|
$
|
162.7
|
|
|
$
|
142.1
|
|
|
|
$
|
207.2
|
|
|
$
|
457.7
|
|
|
$
|
506.0
|
|
|
|
$
|
54.0
|
|
|
$
|
133.4
|
|
Refining margin per crude oil throughput barrel (dollars)
|
|
$
|
3.89
|
|
|
$
|
4.23
|
|
|
|
$
|
5.92
|
|
|
$
|
9.28
|
|
|
|
$
|
11.55
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
Gross profit (loss) per crude oil throughput barrel (dollars)
|
|
$
|
1.25
|
|
|
$
|
1.57
|
|
|
|
$
|
3.20
|
|
|
$
|
5.79
|
|
|
|
$
|
7.55
|
|
|
$
|
8.39
|
|
|
$
|
7.79
|
|
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel (dollars)
|
|
$
|
2.57
|
|
|
$
|
2.60
|
|
|
|
$
|
2.66
|
|
|
$
|
3.44
|
|
|
|
$
|
3.13
|
|
|
$
|
3.92
|
|
|
$
|
7.52
|
|
|
|
$
|
22.73
|
|
|
$
|
4.16
|
|
Operating income (loss)
|
|
|
21.5
|
|
|
|
7.7
|
|
|
|
|
77.1
|
|
|
|
76.7
|
|
|
|
|
123.0
|
|
|
|
245.6
|
|
|
|
144.9
|
|
|
|
|
(63.5
|
)
|
|
|
63.6
|
|
|
|
|
(9)
|
|
During the year ended
December 31, 2003, we recorded an additional charge of
$9.6 million related to the asset impairment of the
refinery and fertilizer plant based on the expected sales price
of the assets in the Initial Acquisition. In addition, we
recorded a charge of $1.3 million for the rejection of
existing contracts while operating under Chapter 11 of the
U.S. Bankruptcy Code.
|
|
(10)
|
|
During the 304 days ended
December 31, 2004, the 174 days ended June 23,
2005, the year ended December 31, 2006 and the year ended
December 31, 2007, we recognized a loss of
$7.2 million, $8.1 million, $23.4 million and
$1.3 million, respectively, on early extinguishment of debt.
|
|
(11)
|
|
Historical dividends per unit for
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.
|
|
(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
the Bankruptcy Code.
SOP 90-7
requires that pre-petition liabilities be segregated in the
balance sheet.
|
75
|
|
|
(14)
|
|
Minority interest reflects common
stock in two of our subsidiaries owned by John J. Lipinski
(which were exchanged for shares of our common stock with an
equivalent value prior to the consummation of our initial public
offering). Minority interest at December 31, 2007 reflects
Coffeyville Acquisition III LLCs ownership of the
managing general partner interest and IDRs of the Partnership.
|
|
(15)
|
|
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.
|
|
(16)
|
|
On-stream factor is the total
number of hours operated divided by the total number of hours in
the reporting period. Excluding the impact of turnarounds at the
nitrogen fertilizer facility in the third quarter of 2004 and
2006, (i) the on-stream factors for the year ended
December 31, 2004 would have been 95.6% for gasifier, 83.1%
for ammonia and 86.7% for UAN and (ii) the on-stream
factors for the year ended December 31, 2006 would have
been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN.
Excluding the impact of the flood during the weekend of
June 30, 2007, the on-stream factors for the year ended
December 31, 2007 would have been 94.6% for gasifier, 92.4%
for ammonia and 83.9% for UAN.
|
76
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our
financial condition and results of operations in conjunction
with our financial statements and related notes included
elsewhere in this prospectus. This discussion and analysis
contains forward-looking statements that involve risks,
uncertainties and assumptions. Our actual results may differ
materially from those anticipated in these forward-looking
statements as a result of a number of factors, including, but
not limited to, those set forth under Risk Factors,
Cautionary Note Regarding Forward-Looking Statements
and elsewhere in this prospectus.
Overview and
Executive Summary
We are an independent refiner and marketer of high value
transportation fuels. In addition, we currently own all of the
interests (other than the managing general partner interest and
associated IDRs) in a limited partnership which produces the
nitrogen fertilizers ammonia and UAN. At current natural gas and
pet coke prices, the nitrogen fertilizer business is the lowest
cost producer and marketer of ammonia and UAN in North America.
We operate under two business segments: petroleum and nitrogen
fertilizer. For the fiscal years ended December 31, 2005,
2006 and 2007, we generated combined net sales of
$2.4 billion, $3.0 billion and $3.0 billion,
respectively. Our petroleum business generated
$2.3 billion, $2.9 billion and $2.8 billion of
our combined net sales, respectively, over these periods, with
the nitrogen fertilizer business generating substantially all of
the remainder. In addition, during these periods, our petroleum
business contributed 74%, 87% and 78% of our combined operating
income, respectively, with the nitrogen fertilizer business
contributing substantially all of the remainder. For the three
months ended March 31, 2008, we generated combined net
sales of $1.22 billion, with the petroleum business
generating $1.17 billion of our combined net sales, and the
nitrogen fertilizer business generating substantially all of the
remainder. For the same period, the petroleum business
contributed 73% of our combined operating income and the
nitrogen fertilizer business generated substantially all of the
remainder.
Petroleum Business.
Our petroleum
business includes a 115,000 bpd complex full coking
medium-sour crude refinery in Coffeyville, Kansas. In addition,
supporting businesses include (1) a crude oil gathering
system serving central Kansas, northern Oklahoma and
southwestern Nebraska, (2) storage and terminal facilities
for asphalt and refined fuels in Phillipsburg, Kansas,
(3) a 145,000 bpd pipeline system that transports
crude oil to our refinery and associated crude oil storage tanks
with a capacity of approximately 1.2 million barrels and
(4) a rack marketing division supplying product through
tanker trucks directly to customers located in close geographic
proximity to Coffeyville and Phillipsburg and at throughput
terminals on Magellans refined products distribution
systems. In addition to rack sales (sales which are made at
terminals into third-party tanker trucks), we make bulk sales
(sales through third-party pipelines) into the mid-continent
markets via Magellan and into Colorado and other destinations
utilizing the product pipeline networks owned by Magellan,
Enterprise and NuStar. Our refinery is situated approximately
100 miles from Cushing, Oklahoma, one of the largest crude
oil trading and storage hubs in the United States. Cushing is
supplied by numerous pipelines from locations including the
U.S. Gulf Coast and Canada, providing us with access to
virtually any crude variety in the world capable of being
transported by pipeline.
Throughput (the volume processed at a facility) at the refinery
has markedly increased since July 2005. Managements focus
on crude slate optimization (the process of determining the most
economic crude oils to be refined), reliability, technical
support and operational excellence coupled with prudent
expenditures on equipment has significantly improved the
operating metrics of the refinery. Historically, the refinery
operated at an average crude throughput rate of less than
90,000 bpd. The plant averaged over 102,000 bpd of
crude throughput in the second quarter of 2006, over
94,500 bpd for all 2006 and over 110,000 in the fourth
quarter of 2007 with maximum daily rates in excess of
77
120,000 bpd for the fourth quarter of 2007. Not only were
rates increased but yields were simultaneously improved. Since
June 2005, the refinery has eclipsed monthly record
(30-day)
processing rates on approximately 70% of the individual units on
site.
Crude is supplied to our refinery through our owned and leased
gathering system and by a Plains pipeline from Cushing,
Oklahoma. We maintain capacity on the Spearhead Pipeline from
Canada and receive foreign and deepwater domestic crudes via the
Seaway Pipeline system. We have also committed to additional
pipeline capacity on the proposed Keystone pipeline project
currently under development. We also maintain leased storage in
Cushing to facilitate optimal crude purchasing and blending. We
have significantly expanded the variety of crude grades
processed in any given month from a limited few to over a dozen,
including onshore and offshore domestic grades, various Canadian
sours, heavy sours and sweet synthetics, and a variety of South
American and West African imported grades. As a result of the
crude slate optimization, we have improved the crude consumed
cost discount to WTI from $3.45 per barrel in 2005 to $4.57 per
barrel in 2006, $5.04 per barrel in 2007 and $5.31 per barrel in
the first quarter of 2008.
Nitrogen Fertilizer Business.
The
nitrogen fertilizer segment consists of our interest in CVR
Partners, LP, a limited partnership controlled by our
affiliates. The nitrogen fertilizer business consists of a
nitrogen fertilizer manufacturing facility, including (1) a
1,225
ton-per-day
ammonia unit, (2) a 2,025
ton-per-day
UAN unit and (3) an 84 million standard cubic foot per
day gasifier complex, which consumes approximately 1,500 tons
per day of pet coke to produce hydrogen. In 2007, the nitrogen
fertilizer business produced approximately 326,662 tons of
ammonia, of which approximately 72% was upgraded into
approximately 576,888 tons of UAN. At current natural gas and
pet coke prices, the nitrogen fertilizer business is the lowest
cost producer and marketer of ammonia and UAN fertilizers in
North America. The nitrogen fertilizer business generated net
sales of $173.0 million, $162.5 million and
$165.9 million, and operating income of $71.0 million,
$36.8 million and $46.6 million, for the years ended
December 31, 2005, 2006 and 2007, respectively. The
nitrogen fertilizer business generated net sales of
$62.6 million and operating income of $26.0 million
for the three months ended March 31, 2008.
The nitrogen fertilizer plant in Coffeyville, Kansas includes a
pet coke gasifier that produces high purity hydrogen which in
turn is converted to ammonia at a related ammonia synthesis
plant. Ammonia is further upgraded into UAN solution in a
related UAN unit. Pet coke is a low value
by-product
of the refinery coking process. On average during the last four
years, more than 75% of the pet coke consumed by the nitrogen
fertilizer plant was produced by our refinery. The nitrogen
fertilizer business obtains most of its pet coke via a long-term
coke supply agreement with us. As such, the nitrogen fertilizer
business benefits from high natural gas prices, as fertilizer
prices generally increase with natural gas prices, without a
directly related change in cost (because pet coke is used as a
primary raw material rather than natural gas).
The nitrogen fertilizer plant is the only commercial facility in
North America utilizing a pet coke gasification process to
produce nitrogen fertilizers. The use of low cost by-product pet
coke from the adjacent oil refinery (rather than natural gas) to
produce hydrogen provides the facility with a significant
competitive advantage given the currently high and volatile
natural gas prices. The nitrogen fertilizer business
competition utilizes natural gas to produce ammonia.
Historically, pet coke has been a less expensive feedstock than
natural gas on a per-ton of fertilizer produced basis.
Capital Projects.
Management has
identified, developed and substantially completed several
significant capital projects since June 2005 with a total cost
of approximately $522 million (including $170 million
in expenditures for our refinery expansion project, excluding
$3.7 million in related capitalized interest). Major
projects include construction of a new diesel hydrotreater, a
new continuous catalytic reformer, a new sulfur recovery unit, a
new plant-wide flare system, a technology upgrade to the fluid
catalytic cracking unit and a refinery-wide capacity expansion.
Once completed, these projects are intended to significantly
enhance the profitability of the refinery in environments of
78
high crack spreads and allow the refinery to operate more
profitably at lower crack spreads than is currently possible.
The spare gasifier at the nitrogen fertilizer plant was expanded
in 2006, increasing ammonia production by 6,500 tons per year.
In addition, the nitrogen fertilizer plant is moving forward
with an approximately $120 million fertilizer plant
expansion, of which approximately $11 million was incurred
as of March 31, 2008. We estimate this expansion will
increase the nitrogen fertilizer plants capacity to
upgrade ammonia into premium-priced UAN by approximately 50%.
Management currently expects to complete this expansion in July
2010. This project is also expected to improve the nitrogen
fertilizer business cost structure by eliminating the need
for rail shipments of ammonia, thereby reducing the risks
associated with such rail shipments and avoiding anticipated
cost increases in such transport.
Recent
Developments
During the second quarter of 2008, we are enjoying unprecedented
fertilizer prices which have contributed favorably to our
earnings. Strong industry fundamentals have led current demand
for nitrogen fertilizers to all time highs. U.S. corn
inventories at the end of the 2008-2009 fertilizer year are
projected to be at 673 million bushels, which is the lowest
level since 1995-1996. Corn prices are at record high levels,
and corn planting for 2008-2009 is projected to be higher than
2007-2008. Nitrogen fertilizer prices are at record high levels
due to increased demand and increasing worldwide natural gas
prices. In addition, nitrogen fertilizer prices, which
historically showed a positive correlation with natural gas
prices, have been decoupled from, and increased substantially
more than, natural gas prices in 2007 and 2008. In addition to
demand driven by biofuel fuel production, the quest for
healthier lives and better diets in developing countries is a
primary driving factor behind the increased global demand for
fertilizers. As of June 16, 2008, our order book for UAN
included 367,825 tons at an average netback price of $326.56 per
ton and 34,898 tons of ammonia at an average netback price of
$620.61 per ton.
At the same time, however, crude oil prices have reached record
levels, and while crack spreads have increased to historically
high absolute values, they are below historical levels as a
percentage of crude oil prices. Because crack spreads as a
percentage of crude oil prices have not kept pace with
increasing crude oil prices, our earnings will be negatively
impacted in the second quarter of 2008. The Cash Flow Swap will
also have a material negative impact on our earnings through at
least June 2009 due to the fact that losses on the Cash Flow
Swap increase as crack spreads in absolute terms increase. In
addition, our second quarter has been negatively impacted by
unplanned downtime at the fertilizer plant and the refinery and
increase in non-cash share-based compensation costs as a result
of our increased stock price.
We have begun negotiations to enter into a new
$25.0 million senior secured term loan, or the proposed
senior secured credit facility, which we anticipate will contain
covenants substantially similar to our existing credit facility.
We have not entered into any agreement regarding this new credit
facility, and there is no guarantee that we will be able to
enter into the proposed senior secured credit facility on the
terms described herein or at all.
Restatement of
Year Ended December 31, 2007 and
Quarter Ended September 30, 2007 Financial
Statements
On April 23, 2008, the audit committee of our board of
directors and management concluded that our previously issued
consolidated financial statements for the year ended
December 31, 2007 and the related quarter ended
September 30, 2007 contained errors. We arrived at this
conclusion during the course of our closing process and review
for the quarter ended March 31, 2008. As a result of these
errors, management concluded that our internal control over
financial reporting was not adequate to determine the cost of
crude oil at period end. Specifically, the Companys
policies and procedures for estimating the cost of crude oil and
reconciling these estimates to vendor invoices
79
were not effective. Additionally, the Companys supervision
and review of this estimation and reconciliation process was not
operating at a level of detail adequate to identify the
deficiencies in the process. Management concluded that these
deficiencies were material weaknesses in our internal control
over financial reporting. A material weakness is a deficiency,
or a combination of deficiencies, in internal control over
financial reporting, such that there is a reasonable possibility
that a material misstatement of the Companys annual or
interim financial statements will not be prevented or detected
on a timely basis. Due to these material weaknesses, our
management also concluded that we did not maintain effective
disclosure controls and procedures as of December 31, 2007.
Our restated financial results were filed with the SEC with a
Form 10-K/A
on May 8, 2008. See footnote 2 to our consolidated
financial statements for the year ended December 31, 2007
included elsewhere in this prospectus. All information presented
in this prospectus reflects our restated financial results.
In order to remediate the material weaknesses described above,
our management is in the process of designing, implementing and
enhancing controls to ensure the proper accounting for the
calculation of the cost of crude oil. These remedial actions
include, among other things, (1) centralizing all crude oil
cost accounting functions, (2) adding additional layers of
accounting review with respect to our crude oil cost accounting
and (3) adding additional layers of business review with
respect to the computation of our crude oil costs.
All of the information presented in this prospectus reflects our
restated financial results.
CVR Energys
Initial Public Offering
On October 26, 2007, we completed an initial public
offering of 23,000,000 shares of our common stock. The
initial public offering price was $19.00 per share. The net
proceeds to us from the sale of our common stock were
approximately $408.5 million, after deducting underwriting
discounts and commissions, but before deduction of offering
expenses. We also incurred approximately $11.4 million of
other costs related to the initial public offering.
The net proceeds from the offering were used to repay
$280.0 million of our outstanding term loan debt and to
repay in full our $25.0 million secured credit facility and
$25.0 million unsecured credit facility. We also repaid
$50.0 million of indebtedness under our revolving credit
facility.
In connection with the initial public offering, we also became
the indirect owner of Coffeyville Resources, LLC and all of its
refinery assets. This was accomplished by the issuance of
62,866,720 shares of our common stock to certain entities
controlled by our majority stockholders pursuant to a stock
split in exchange for the interests in certain subsidiaries of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC. Immediately following the completion of the offering, there
were 86,141,291 shares of common stock outstanding,
excluding any restricted shares issued.
Major Influences
on Results of Operations
Petroleum
Business
Our earnings and cash flows from our petroleum operations are
primarily affected by the relationship between refined product
prices and the prices for crude oil and other feedstocks.
Feedstocks are petroleum products, such as crude oil and natural
gas liquids, that are processed and blended into refined
products. The cost to acquire feedstocks and the price for which
refined products are ultimately sold depend on factors beyond
our control, including the supply of, and demand for, crude oil,
as well as gasoline and other refined products which, in turn,
depend on, among other factors, changes in domestic and foreign
economies, weather conditions, domestic and foreign political
affairs, production levels, the availability of imports, the
marketing of competitive fuels and the extent of government
regulation. Because we apply
first-in,
first-out, or FIFO, accounting to value our
80
inventory, crude oil price movements may impact net income in
the short term because of instantaneous changes in the value of
the minimally required, unhedged on hand inventory. The effect
of changes in crude oil prices on our results of operations is
influenced by the rate at which the prices of refined products
adjust to reflect these changes.
Feedstock and refined product prices are also affected by other
factors, such as product pipeline capacity, local market
conditions and the operating levels of competing refineries.
Crude oil costs and the prices of refined products have
historically been subject to wide fluctuations. An expansion or
upgrade of our competitors facilities, price volatility,
international political and economic developments and other
factors beyond our control are likely to continue to play an
important role in refining industry economics. These factors can
impact, among other things, the level of inventories in the
market, resulting in price volatility and a reduction in product
margins. Moreover, the refining industry typically experiences
seasonal fluctuations in demand for refined products, such as
increases in the demand for gasoline during the summer driving
season and for home heating oil during the winter, primarily in
the Northeast.
Crude oil costs are at historic highs. West Texas Intermediate
crude oil averaged $97.82 per barrel for the three months ended
March 31, 2008, as compared to $58.27 per barrel during the
comparable period in 2007. WTI crude oil prices averaged over
$105 per barrel in March 2008 and had spiked to over $138.75 per
barrel as of June 6, 2008. There are a number of reasons
why high crude oil costs and current crack spreads have a
negative impact on our business. First, as crack spreads
increase in absolute terms in connection with higher crude oil
prices, we realize increasing losses on the Cash Flow Swap. We
expect the Cash Flow Swap will continue to have a material
negative effect on our earnings at least through June 2009.
Second, every barrel of crude oil that we process yields
approximately 88% high performance transportation fuels and
approximately 12% less valuable byproducts such as pet coke,
slurry and sulfur and volumetric losses (lost volume resulting
from the change from liquid form to solid). Whereas crude oil
costs have increased, sales prices for many byproducts have not
increased in the same proportions. As a result, we lose money on
byproduct sales (and from the inherent lost volume in shifting
from liquid to solid form), resulting in a reduction to our
earnings.
In order to assess our operating performance, we compare our net
sales, less cost of product sold (refining margin), against an
industry refining margin benchmark. The industry refining margin
is calculated by assuming that two barrels of benchmark light
sweet crude oil is converted into one barrel of conventional
gasoline and one barrel of distillate. This benchmark is
referred to as the 2-1-1 crack spread. Because we calculate the
benchmark margin using the market value of New York Mercantile
Exchange (NYMEX) gasoline and heating oil against the market
value of NYMEX WTI (WTI) crude oil, we refer to the benchmark as
the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread.
The 2-1-1
crack spread is expressed in dollars per barrel and is a proxy
for the per barrel margin that a sweet crude refinery would earn
assuming it produced and sold the benchmark production of
gasoline and heating oil. The 2-1-1 crack spreads were
significantly narrower in the first quarter of 2008 as a
percentage of crude oil prices when compared to the first
quarter of 2007. As a percentage of crude oil prices, the 2-1-1
crack spread was approximately 21% in the first quarter of 2007
but only 12% in the first quarter of 2008.
Although the 2-1-1 crack spread is a benchmark for our refinery
margin, because our refinery has certain feedstock costs
and/or
logistical advantages as compared to a benchmark refinery and
our product yield is less than total refinery throughput, the
crack spread does not account for all the factors that affect
refinery margin. Our refinery is able to process a blend of
crude oil that includes quantities of heavy and medium-sour
crude oil that has historically cost less than WTI crude oil. We
measure the cost advantage of our crude oil slate by calculating
the spread between the price of our delivered crude oil to the
price of WTI crude oil, a light sweet crude oil. The spread is
referred to as our consumed crude differential. Our refinery
margin can be impacted significantly by the consumed crude
differential. Our consumed crude differential will move
directionally with changes in the West Texas Sour (WTS)
differential to WTI and the West Canadian Select (WCS)
differential to WTI as both
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these differentials indicate the relative price of heavier, more
sour, slate to WTI. The WCS-WTI differential for the first
quarter of 2008 was $19.84 a barrel as compared to $14.80 a
barrel in the first quarter of 2007. The differential for the
fourth quarter of 2007 was $32.60 a barrel. The correlation
between our consumed crude differential and published
differentials will vary depending on the volume of light
medium-sour crude and heavy sour crude we purchase as a percent
of our total crude volume and will correlate more closely with
such published differentials the heavier and more sour the crude
oil slate.
We produce a high volume of high value products, such as
gasoline and distillates. Approximately 39% of our product slate
is ultra low sulfur diesel, which provides us with tax credits
and is currently selling at higher margins than gasoline (which
represents 48% of our refined products). The balance of our
production is devoted to other products, including the petroleum
coke used by the nitrogen fertilizer business. We benefit from
the fact that our marketing region consumes more refined
products than it produces so that the market prices of our
products have to be high enough to cover the logistics cost for
the U.S. Gulf Coast refineries to ship into our region. The
result of this logistical advantage and the fact the actual
product specification used to determine the NYMEX is different
from the actual production in the refinery is that prices we
realize are different than those used in determining the 2-1-1
crack spread. The difference between our price and the price
used to calculate the 2-1-1 crack spread is referred to as
gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis,
and heating oil PADD II, Group 3 vs. NYMEX basis, or heating oil
basis.
Our direct operating expense structure is also important to our
profitability. Major direct operating expenses include energy,
employee labor, maintenance, contract labor, and environmental
compliance. Our predominant variable cost is energy which is
comprised primarily of electrical cost and natural gas. We are
therefore sensitive to the movements of natural gas prices.
Consistent, safe, and reliable operations at our refinery are
key to our financial performance and results of operations.
Unplanned downtime at our refinery may result in lost margin
opportunity, increased maintenance expense and a temporary
increase in working capital investment and related inventory
position. We seek to mitigate the financial impact of planned
downtime, such as major turnaround maintenance, through a
diligent planning process that takes into account the margin
environment, the availability of resources to perform needed
maintenance, feedstocks and other factors.
We purchase most of our crude oil using a credit intermediation
agreement. Our credit intermediation agreement is structured
such that we take title, and the price of the crude oil is set,
when it is metered and delivered at Broome Station, which is
connected to, and located approximately 22 miles from, our
refinery. Once delivered at Broome Station, the crude oil is
delivered to our refinery through two of our wholly owned
pipelines which begin at Broome Station and end at our refinery.
The crude oil is delivered at Broome Station because Broome
Station is located near our facility and is connected via
pipeline to our facility. The terms of the credit intermediation
agreement provide that we will obtain all of the crude oil for
our refinery, other than the crude we obtain through our own
gathering system, through J. Aron. Once we identify cargos of
crude oil and pricing terms that meet our requirements, we
notify J. Aron and J. Aron then provides credit, transportation
and other logistical services to us for a fee. This agreement
significantly reduces the investment that we are required to
maintain in petroleum inventories relative to our competitors
and reduces the time we are exposed to market fluctuations
before the inventory is priced to a customer.
Because petroleum feedstocks and products are essentially
commodities, we have no control over the changing market.
Therefore, the lower target inventory we are able to maintain
significantly reduces the impact of commodity price volatility
on our petroleum product inventory position relative to other
refiners. This target inventory position is generally not
hedged. To the extent our inventory position deviates from the
target level, we consider risk mitigation activities usually
through the purchase or sale of futures contracts on the New
York Mercantile Exchange, or NYMEX. Our hedging activities carry
customary time, location and product grade basis risks generally
associated with
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hedging activities. Because most of our titled inventory is
valued under the FIFO costing method, price fluctuations on our
target level of titled inventory have a major effect on our
financial results unless the market value of our target
inventory is increased above cost.
Nitrogen
Fertilizer Business
In the nitrogen fertilizer business, earnings and cash flow from
operations are primarily affected by the relationship between
nitrogen fertilizer product prices and direct operating
expenses. Unlike its competitors, the nitrogen fertilizer
business uses minimal natural gas as feedstock and, as a result,
is not directly impacted in terms of cost by high or volatile
swings in natural gas prices. Instead, our adjacent oil refinery
supplies most of the pet coke feedstock needed by the nitrogen
fertilizer business pursuant to a long-term pet coke supply
agreement. The price at which nitrogen fertilizer products are
ultimately sold depends on numerous factors, including the
supply of, and the demand for, nitrogen fertilizer products
which, in turn, depends on, among other factors, the price of
natural gas, the cost and availability of fertilizer
transportation infrastructure, changes in the world population,
weather conditions, grain production levels, the availability of
imports, and the extent of government intervention in
agriculture markets. While net sales of the nitrogen fertilizer
business could fluctuate significantly with movements in natural
gas prices during periods when fertilizer markets are weak and
nitrogen fertilizer products sell at low prices, high natural
gas prices do not force the nitrogen fertilizer business to shut
down its operations because it employs pet coke as a feedstock
to produce ammonia and UAN rather than natural gas.
Nitrogen fertilizer prices are also affected by other factors,
such as local market conditions and the operating levels of
competing facilities. Natural gas costs and the price of
nitrogen fertilizer products have historically been subject to
wide fluctuations. An expansion or upgrade of competitors
facilities, price volatility, international political and
economic developments and other factors are likely to continue
to play an important role in nitrogen fertilizer industry
economics. These factors can impact, among other things, the
level of inventories in the market, resulting in price
volatility and a reduction in product margins. Moreover, the
industry typically experiences seasonal fluctuations in demand
for nitrogen fertilizer products.
The demand for fertilizers is affected by the aggregate crop
planting decisions and fertilizer application rate decisions of
individual farmers. Individual farmers make planting decisions
based largely on the prospective profitability of a harvest,
while the specific varieties and amounts of fertilizer they
apply depend on factors like crop prices, their current
liquidity, soil conditions, weather patterns and the types of
crops planted.
The value of nitrogen fertilizer products is also an important
consideration in understanding our results. The nitrogen
fertilizer business generally upgrades approximately two-thirds
of its ammonia production into UAN, a product that presently
generates a greater value than ammonia. UAN production is a
major contributor to our profitability. In order to assess the
value of nitrogen fertilizer products, we calculate netbacks,
also referred to as plant gate price. Netbacks refer to the unit
price of fertilizer, in dollars per ton, offered on a delivered
basis, excluding shipment costs.
Prices for both ammonia and UAN for the quarter ended
March 31, 2008 reflect strong current demand for these
products. Ammonia plant gate prices averaged $494 per ton for
the quarter ended March 31, 2008, compared to $347 per ton
during the comparable period in 2007. UAN prices averaged $262
per ton for the quarter ended March 31, 2008, compared to
$169 per ton during the comparable 2007 period. The prices for
both ammonia and UAN continue to rise. Our order book as of
June 16, 2008 contains average netback prices for ammonia
and UAN of $327 and $621 per ton, respectively.
The direct operating expense structure of the nitrogen
fertilizer business is also important to its profitability.
Using a pet coke gasification process, the nitrogen fertilizer
business has significantly higher fixed costs than natural
gas-based fertilizer plants. Major direct operating expenses
include
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electrical energy, employee labor, maintenance, including
contract labor, and outside services. These costs comprise the
fixed costs associated with the fertilizer plant.
Variable costs associated with the nitrogen fertilizer plant
have averaged approximately 1.2% of direct operating expenses
over the last 24 months ended December 31, 2007. The
average annual operating costs over the 24 months ended
December 31, 2007 have approximated $65 million, of
which substantially all are fixed in nature.
The nitrogen fertilizer business largest raw material
expense is pet coke, which it purchases from us and third
parties. In 2007, the nitrogen fertilizer business spent
$13.6 million for pet coke. If pet coke prices rise
substantially in the future, the nitrogen fertilizer business
may be unable to increase its prices to recover increased raw
material costs, because market prices for nitrogen fertilizer
products are generally correlated with natural gas prices, the
primary raw material used by its competitors, and not pet coke
prices.
The nitrogen fertilizer business generally undergoes a facility
turnaround every two years. The turnaround typically lasts
15-20 days
each turnaround year and requires approximately
$2-3 million in direct costs per turnaround. The next
facility turnaround is currently scheduled for the fourth
quarter of 2008.
Agreements
Between CVR Energy and the Partnership
In connection with our initial public offering and the transfer
of the nitrogen fertilizer business to the Partnership in
October 2007, we entered into a number of agreements with the
Partnership that govern the business relations between the
parties. These include the coke supply agreement, under which we
sell pet coke to the nitrogen fertilizer business; a services
agreement, in which our management operates the nitrogen
fertilizer business; a feedstock and shared services agreement,
which governs the provision of feedstocks, including hydrogen,
high-pressure steam, nitrogen, instrument air, oxygen and
natural gas; an omnibus agreement, which governs the division of
future business opportunities between the two businesses; a raw
water and facilities sharing agreement, which allocates raw
water resources between the two businesses; an easement
agreement; an environmental agreement; and a lease agreement
pursuant to which we lease office space, storage and laboratory
space to the Partnership.
The price paid by the nitrogen fertilizer business pursuant to
the coke supply agreement is based on the lesser of a coke price
derived from the price received by the Partnership for UAN
(subject to a UAN based price ceiling and floor) and a coke
price index for pet coke. For periods prior to our initial
public offering and the transfer of the nitrogen fertilizer
business to the Partnership, the cost of product sold (exclusive
of depreciation and amortization) in the nitrogen fertilizer
business on our financial statements was based on a coke price
of $15 per ton beginning in March 2004. This is reflected in the
segment data in our historical financial statements as a cost
for the nitrogen fertilizer business and as revenue for the
petroleum business. If the terms of the coke supply agreement
had been in place over each of the past three years, the coke
supply agreement would have resulted in an increase (or
decrease) in cost of product sold (exclusive of depreciation and
amortization) for the nitrogen fertilizer business (and an
increase (or decrease) in revenue for the petroleum business) of
$(1.6) million, $(0.7) million, $(3.5) million
and $2.5 million for the
174-day
period ended June 24, 2005, the
233-day
period ended December 31, 2005, the year ended
December 31, 2006 and the year ended December 31,
2007. There would have been no impact to the consolidated
financial statements as intercompany transactions are eliminated
upon consolidation.
In addition, based on managements current estimates, the
services agreement will result in an annual charge of
approximately $11.5 million (excluding share based
compensation) to the nitrogen fertilizer business for its
portion of expenses which have been historically reflected in
selling, general and administrative expenses (exclusive of
depreciation and amortization) in our consolidated statement of
operations. Historical nitrogen fertilizer segment operating
income would increase $0.8 million, decrease
$0.1 million, increase $7.4 million and increase
$8.9 million for the
174-day
period ended
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June 23, 2005, the
233-day
period ended December 31, 2005, the year ended
December 31, 2006 and the year ended December 31,
2007, respectively, assuming an annualized $11.5 million
charge for the management services in lieu of the historical
allocations of selling, general and administrative expenses. The
petroleum segments operating income would have had
offsetting increases or decreases, as applicable, for these
periods.
The total change to operating income for the nitrogen fertilizer
segment as a result of both the
20-year
coke
supply agreement (which affects cost of product sold (exclusive
of depreciation and amortization)) and the services agreement
(which affects selling, general and administrative expense
(exclusive of depreciation and amortization)), if both
agreements had been in effect over the last three years, would
be an increase of $2.4 million, an increase of
$0.6 million, an increase of $10.9 million and an
increase of $6.4 million for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, the year ended
December 31, 2006 and the year ended December 31,
2007, respectively.
The feedstock and shared services agreement, the raw water and
facilities sharing agreement, the cross-easement agreement and
the environmental agreement are not expected to have a
significant impact on the financial results of the nitrogen
fertilizer business. However, the feedstock and shared services
agreement includes provisions which require the nitrogen
fertilizer business to provide hydrogen to us on a going-forward
basis, as the nitrogen fertilizer business has done in recent
years. This will have the effect of limiting the nitrogen
fertilizer business fertilizer production, because the
nitrogen fertilizer business will not be able to convert this
hydrogen into ammonia. We believe that the addition of our new
catalytic reformer will reduce, to some extent, but not
eliminate, the amount of hydrogen the nitrogen fertilizer
business will need to deliver to us, and we expect the nitrogen
fertilizer business to continue to deliver hydrogen to us. The
feedstock and shared services agreement requires us to
compensate the nitrogen fertilizer business for the value of
production lost due to the hydrogen supply requirement. See
The Nitrogen Fertilizer Limited Partnership
Intercompany Agreements.
Factors Affecting
Comparability of Our Financial Results
Our results over the past three years have been, and our future
periods will be, influenced by the following factors, which are
fundamental to understanding comparisons of our period-to-period
financial performance.
2007 Flood and
Crude Oil Discharge
During the weekend of June 30, 2007, torrential rains in
southeast Kansas caused the Verdigris River to overflow its
banks and flood the town of Coffeyville, Kansas. Our refinery
and nitrogen fertilizer plant, which are located in close
proximity to the Verdigris River, were severely flooded,
sustained major damage and required extensive repairs. Total
gross costs incurred and recorded as of March 31, 2008
related to the third party costs to repair the refinery and
fertilizer facilities were approximately $82.5 million and
$4.0 million, respectively. Additionally, other corporate
overhead and miscellaneous costs incurred and recorded in
connection with the flood as of March 31, 2008 were
approximately $19.3 million. We currently estimate that
approximately $2.1 million in third party costs related to
the repair of flood damaged property will be recorded in future
periods. In addition to the cost of repairing the facilities, we
experienced a significant revenue loss attributable to the
property damage during the period when the facilities were not
in operation.
Despite our efforts to secure the refinery prior to its
evacuation as a result of the flood, we estimate that 1,919
barrels (80,600 gallons) of crude oil and 226 barrels of crude
oil fractions were discharged from our refinery into the
Verdigris River flood waters beginning on or about July 1,
2007. We have substantially completed remediation of the
contamination caused by the crude oil discharge and expect any
remaining minor remedial actions to be completed by
December 31, 2008. Total net costs recorded as of
March 31, 2008 associated with remediation efforts and
third party property
85
damage incurred by the crude oil discharge are approximately
$27.3 million. This amount is net of anticipated insurance
recoveries of $21.4 million.
As of March 31, 2008, we have recorded total gross costs
associated with the repair of, and other matters relating to the
damage to our facilities and with third party and property
damage remediation incurred due to the crude oil discharge of
approximately $154.5 million. Total anticipated insurance
recoveries of approximately $107.2 million have been
recorded as March 31, 2008 (of which $21.5 million has
already been received from insurance carriers by us), resulting
in a net cost of approximately $47.3 million. We have not
estimated any potential fines, penalties or claims that may be
imposed or brought by regulatory authorities or possible
additional damages arising from lawsuits related to the flood.
Refinancing
and Prior Indebtedness
Effective May 10, 2004, Immediate Predecessor entered into
a term loan of $150.0 million and a $75.0 million
revolving loan facility with a syndicate of banks, financial
institutions, and institutional lenders. Both loans were secured
by substantially all of Immediate Predecessors real and
personal property, including receivables, contract rights,
general intangibles, inventories, equipment, and financial
assets. The covenants contained under the new term loan
contained restrictions which limited the ability to pay
dividends at the complete discretion of our board of directors.
The Immediate Predecessor had no other restrictions on its
ability to make dividend payments. Once any debt requirements
were met, any dividends were at the discretion of our board of
directors. There were outstanding borrowings of
$148.9 million under the term loan and less than
$0.1 million under the revolving loan facility at
December 31, 2004. Outstanding borrowings on June 23,
2005 were repaid in connection with the Subsequent Acquisition.
Effective June 24, 2005, Coffeyville Resources, LLC entered
into a first lien credit facility and a second lien credit
facility. The first lien credit facility was in an aggregate
amount not to exceed $525.0 million, consisting of
$225.0 million tranche B term loans;
$50.0 million of delayed draw term loans available for the
first 18 months of the agreement and subject to accelerated
payment terms; a $100.0 million revolving loan facility;
and a funded letter of credit facility (funded facility) of
$150.0 million for the benefit of the Cash Flow Swap
provider. The first lien credit facility was secured by
substantially all of Coffeyville Resources, LLCs assets.
In June 2006 the first lien credit facility was amended and
restated and the $225.0 million of tranche B term
loans were refinanced with $225.0 million of tranche C
term loans. The second lien credit facility was a
$275.0 million term loan facility secured by substantially
all of Coffeyville Resources, LLCs assets on a second
priority basis.
On December 28, 2006, Coffeyville Resources, LLC entered
into a new credit facility and used the proceeds thereof to
repay its then existing first lien credit facility and second
lien credit facility, and to pay a dividend to the members of
Coffeyville Acquisition LLC. The credit facility provides
financing of up to $1.075 billion, consisting of
$775.0 million of tranche D term loans, a
$150.0 million revolving credit facility, and a funded
letter of credit facility of $150.0 million issued in
support of the Cash Flow Swap. The credit facility is secured by
substantially all of Coffeyville Resources, LLCs assets.
See Description of Our Indebtedness and the Cash Flow
Swap. As a result, interest expense for the year ended
December 31, 2007 was significantly higher than interest
expense for the year ended December 31, 2006. Consolidated
interest expense for the year ended December 31, 2007 was
$61.1 million as compared to interest expense of
$43.9 million for the year ended December 31, 2006. At
December 31, 2006, we had a balance of $775.0 million
on our term loan facility.
The 2007 flood and crude oil discharge had a significant
negative effect on our liquidity in July/August 2007. As a
result, in August 2007, our subsidiaries entered into a
$25.0 million secured facility, a $25.0 million
unsecured facility and a $75.0 million unsecured facility.
Our statement of operations for the year ended December 31,
2007 includes $0.9 million in interest expense related to
these facilities with no comparable amount for the same period
in the prior year.
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In October 2007, we paid down $280.0 million of outstanding
long-term debt with initial public offering proceeds. In
addition, proceeds of our initial public offering were used to
repay in full our $25.0 million secured credit facility,
our $25.0 million unsecured credit facility and
$50.0 million of indebtedness under our revolving credit
facility. No amounts were drawn under the $75.0 million
unsecured facility, and it terminated upon consummation of our
initial public offering.
Our statements of operations for the three months ended
March 31, 2008 includes interest expense of
$11.3 million on the term debt of $488.0 million.
Interest expense associated with the term debt for the three
months ended March 31, 2007 totaled $11.9 million.
Term debt as of March 31, 2007 totaled $775.0 million.
J. Aron
Deferrals
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, Coffeyville Resources, LLC
entered into several deferral agreements with J. Aron with
respect to the Cash Flow Swap, which is a series of commodity
derivative arrangements whereby if crack spreads in absolute
terms fall below a fixed level, J. Aron agreed to pay the
difference to us, and if crack spreads in absolute terms rise
above a fixed level, we agreed to pay the difference to J. Aron.
These deferral agreements deferred to August 31, 2008 the
payment of approximately $123.7 million (plus accrued
interest) which we owed to J. Aron. We are required to use 37.5%
of our consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferred amounts, but as of
March 31, 2008, we were not required to prepay any portion
of the deferred amount.
Change in
Reporting Entity as a Result of the Initial Public
Offering
Prior to our initial public offering in October 2007, our
operations were conducted by an operating partnership,
Coffeyville Resources, LLC. The reporting entity of the
organization was also a partnership. Immediately prior to the
closing of our initial public offering, Coffeyville Resources,
LLC became an indirect, wholly-owned subsidiary of CVR Energy.
As a result, for periods ending after October 2007, we report
our results of operations and financial condition as a
corporation on a consolidated basis rather than as an operating
partnership.
Public Company
Expenses
We believe that our general and administrative expenses will
increase due to the costs of operating as a public company, such
as increases in legal, accounting and compliance, insurance
premiums, and investor relations. We estimate that the increase
in these costs will total approximately $2.5 million to
$3.0 million on an annual basis, excluding the costs
associated with the initial implementation of our Sarbanes-Oxley
Section 404 internal controls review and testing. Our
financial statements following the initial public offering
reflect the impact of these expenses, whereas our financial
statements for periods prior to the initial public offering do
not reflect these expenses.
2007
Turnaround
In April 2007, we completed a planned turnaround of our refining
plant at a total cost approximating $80.4 million, which
included $66.0 million recorded in the first quarter of
2007. The refinery processed crude until February 11, 2007
at which time a staged shutdown of the refinery began. The
refinery recommenced operations on March 22, 2007 and
continually increased crude oil charge rates until all of the
key units were restarted by April 23, 2007. The turnaround
significantly impacted our financial results for 2007 and had no
impact on our 2008 results.
2005
Acquisition
On June 24, 2005, pursuant to a stock purchase agreement
dated May 15, 2005, Coffeyville Acquisition LLC acquired
all of the subsidiaries of Coffeyville Group Holdings, LLC. See
Note 1 to our consolidated financial statements included
elsewhere in this prospectus. We refer to this acquisition
87
as the Subsequent Acquisition, and we refer to our
post-June 24, 2005 operations as Successor. As a result of
certain adjustments made in connection with this acquisition, a
new basis of accounting was established on the date of the
acquisition and the results of operations for the 233 days
ended December 31, 2005 are not comparable to prior periods.
Cash Flow
Swap
In connection with the Subsequent Acquisition in June 2005,
Coffeyville Resources, LLC entered into a series of commodity
derivative contracts, the Cash Flow Swap, in the form of three
long-term swap agreements. Based on crude oil capacity of
115,000 bpd, the Cash Flow Swap represents approximately
58% and 14% of crude oil capacity for the periods July 1,
2008 through June 30, 2009 and July 1, 2009 through
June 30, 2010, respectively. Under the terms of our credit
facility and upon meeting specific requirements related to our
leverage ratio and our credit ratings, we are permitted to
reduce the Cash Flow Swap to 35,000 bpd, or approximately
30% of expected crude oil capacity, for the period from
April 1, 2008 through December 31, 2008 and terminate
the Cash Flow Swap in 2009 and 2010, so long as at the time of
reduction or termination, we pay the amount of unrealized losses
associated with the amount reduced or terminated. We have
determined that the Cash Flow Swap does not qualify as a hedge
for hedge accounting purposes under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities.
Therefore, in the financial statements for all periods after
July 1, 2005, the statement of operations reflects all the
realized and unrealized gains and losses from this swap. For the
233-day
period ending December 31, 2005, we recorded realized and
unrealized losses of $59.3 million and $235.9 million,
respectively. For the year ending December 31, 2006, we
recorded net realized losses of $46.8 million and net
unrealized gains of $126.8 million. For the year ended
December 31, 2007, we recorded net realized losses of
$157.2 million and net unrealized losses of
$103.2 million. The current environment of high and rising
crude oil prices has led to higher crack spreads in absolute
terms but significantly narrower crack spreads as a percentage
of crude oil prices. As a result, the Cash Flow Swap, under
which payments are calculated based on crack spreads in absolute
terms has had and continues to have a material negative impact
on our earnings. Due to the Cash Flow Swap, we estimate we will
owe J. Aron approximately $54 million on July 8, 2008
for crude oil we settled or will settle with respect to the
quarter ending June 30, 2008, based on June 16, 2008
pricing.
Property Tax
Assessments
Our results of operations for the twelve months ending
December 31, 2005 and 2006 reflect no property tax for our
fertilizer facility (due to a tax abatement) and only a small
property tax for our refinery. Our results of operations for the
year ended December 31, 2007 reflect a substantially
increased property tax for our refinery, and our results of
operations for the three months ended March 31, 2008
reflect a substantially increased property tax for our
fertilizer facility, as a result of new tax assessments by
Montgomery County, Kansas and the end of the tax abatement. We
have appealed both assessments. The refinery was again
reappraised effective January 1, 2008. We have also
appealed this new assessment, and believe that tax exemptions
should apply to any incremental tax which would be owed as a
result of the new assessment.
Consolidation of
Nitrogen Fertilizer Limited Partnership
Prior to the consummation of our initial public offering, we
transferred our nitrogen fertilizer business to the Partnership
and sold the managing general partner interest in the
Partnership to a new entity owned by our controlling
stockholders and senior management. As of the date of this
prospectus, we own all of the interests in the Partnership
(other than the managing general partner interest and associated
IDRs) and are entitled to all cash that is distributed by the
Partnership. The Partnership is operated by our senior
management pursuant to a services agreement among us, the
managing general partner and the Partnership. The Partnership is
managed by the managing general partner and, to the extent
described below, us, as special general partner. As special
general partner of the Partnership, we have joint management
rights regarding the appointment, termination and
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compensation of the chief executive officer and chief financial
officer of the managing general partner, have the right to
designate two members to the board of directors of the managing
general partner and have joint management rights regarding
specified major business decisions relating to the Partnership.
We consolidate the Partnership for financial reporting purposes.
We have determined that following the sale of the managing
general partner interest to an entity owned by our controlling
stockholders and senior management, the Partnership is a
variable interest entity (VIE) under the provisions
of FASB Interpretation No. 46R
Consolidation
of Variable Interest Entities
(FIN No. 46R).
Using criteria in FIN No. 46R, management has
determined that we are the primary beneficiary of the
Partnership, although 100% of the managing general partner
interest is owned by a new entity owned by our controlling
stockholders and senior management outside our reporting
structure. Since we are the primary beneficiary, the financial
statements of the Partnership remain consolidated in our
financial statements. The managing general partners
interest is reflected as a minority interest on our balance
sheet.
The conclusion that we are the primary beneficiary of the
Partnership and required to consolidate the Partnership as a
variable interest entity is based upon the fact that
substantially all of the expected losses are absorbed by the
special general partner, which we own. Additionally,
substantially all of the equity investment at risk was
contributed on behalf of the special general partner, with
nominal amounts contributed by the managing general partner. The
special general partner is also expected to receive the
majority, if not substantially all, of the expected returns of
the Partnership through the Partnerships cash distribution
provisions.
We will need to reassess from time to time whether we remain the
primary beneficiary of the Partnership in order to determine if
consolidation of the Partnership remains appropriate on a going
forward basis. Should we determine that we are no longer the
primary beneficiary of the Partnership, we will be required to
deconsolidate the Partnership in our financial statements for
accounting purposes on a going-forward basis. In that event, we
would be required to account for our investment in the
Partnership under the equity method of accounting, which would
affect our reported amounts of consolidated revenues, expenses
and other income statement items.
The principal events that would require the reassessment of our
accounting treatment related to our interest in the Partnership
include:
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a sale of some or all of our partnership interests to an
unrelated party;
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a sale of the managing general partner interest to a third party;
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the issuance by the Partnership of partnership interests to
parties other than us or our related parties; and
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the acquisition by us of additional partnership interests
(either new interests issued by the Partnership or interests
acquired from unrelated interest holders).
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In addition, we would need to reassess our consolidation of the
Partnership if the Partnerships governing documents or
contractual arrangements are changed in a manner that
reallocates between us and other unrelated parties either
(1) the obligation to absorb the expected losses of the
Partnership or (2) the right to receive the expected
residual returns of the Partnership.
Industry
Factors
Petroleum
Business
Earnings for our petroleum business depend largely on our
refining margins, which have been and continue to be volatile.
Crude oil and refined product prices depend on factors beyond
our control.
89
While it is impossible to predict refining margins due to the
uncertainties associated with global crude oil supply and global
and domestic demand for refined products, we believe that
refining margins for U.S. refineries will generally remain
above those experienced in the periods prior to 2003. Growth in
demand for refined products in the United States, particularly
transportation fuels, continues to exceed the ability of
domestic refiners to increase capacity. In addition, changes in
global supply and demand and other factors have affected the
extent to which product importation to the United States can
relieve domestic supply deficits. Our marketing region continues
to be undersupplied and is a net importer of transportation
fuels.
Crude oil discounts also contribute to our petroleum business
earnings. Discounts for sour and heavy sour crude oils compared
to sweet crudes continue to fluctuate widely. The worldwide
production of sour and heavy sour crude oil, continuing demand
for light sweet crude oil, and the increasing volumes of
Canadian sours to the mid-continent continue to cause wide
swings in discounts. As a result of our expansion project, we
continue to increase volumes of heavy sour Canadian crudes and
reduce our dependence on more expensive light sweet crudes.
Nitrogen
Fertilizer Business
Global demand for fertilizers typically grows at predictable
rates and tends to correspond to growth in grain production and
pricing. Global fertilizer demand is driven in the long term
primarily by population growth, increases in disposable income
and associated improvements in diet. Short-term demand depends
on world economic growth rates and factors creating temporary
imbalances in supply and demand. We operate in a highly
competitive, global industry. Our products are globally-traded
commodities and, as a result, we compete principally on the
basis of delivered price. We are geographically advantaged to
supply nitrogen fertilizer products to the Corn Belt compared to
U.S. Gulf Coast producers and our gasification process
requires approximately 1% of the natural gas relative to natural
gas-based fertilizer producers.
Currently, the nitrogen fertilizer market is driven by an almost
unprecedented increase in demand. According to the United States
Department of Agriculture (USDA), U.S. farmers
planted 92.9 million acres of corn in 2007, exceeding the
2006 planted area by 19%. The actual planted acreage is the
highest on record since 1944, when farmers planted
95.5 million acres of corn. The USDA is forecasting as of
March 2008 that total U.S. planted corn acreage in 2008
will decline to 86 million acres. Despite this decrease,
Blue Johnson estimates that nitrogen fertilizer consumption by
farm users will increase by one million tons due to the need to
correct for under fertilization of corn in 2007, a forecasted
increase in total planted wheat acreage and very strong crop
prices. This estimated increase in nitrogen usage translates
into an annual increase of 3.3 million tons of UAN, or
approximately five times our total 2008 estimated UAN production.
Total worldwide ammonia capacity has been growing. A large
portion of the net growth has been in China and is attributable
to China maintaining its self-sufficiency with regards to
ammonia. Excluding China and the former Soviet Union, the trend
in net ammonia capacity has been essentially flat since the late
1990s, as new plant construction has been offset by plant
closures in countries with high-cost feedstocks. The high cost
of capital is also limiting capacity increase. Todays
strong market growth appears to be readily absorbing the latest
capacity additions.
Earnings for the nitrogen fertilizer business depend largely on
the prices of nitrogen fertilizer products, the floor price of
which is directly influenced by natural gas prices. Natural gas
prices have been and continue to be volatile. In addition,
nitrogen fertilizer prices have been decoupled from their
historical correlation with natural gas prices in recent years
and increased substantially more than natural gas prices in 2007
and 2008 (based on data provided by Blue Johnson).
90
Results of
Operations
In this Results of Operations section, we first
review our business on a consolidated basis, and then separately
review the results of operations of each of our petroleum and
nitrogen fertilizer businesses on a standalone basis.
Consolidated
Results of Operations
The period-to-period comparisons of our results of operations
have been prepared using the historical periods included in our
financial statements. As discussed in Note 1 to our
consolidated financial statements, effective June 24, 2005,
Successor acquired the net assets of Immediate Predecessor in a
business combination accounted for as a purchase. As a result of
this acquisition, the consolidated financial statements for the
periods after the acquisition are presented on a different cost
basis than that for the period before the acquisition and,
therefore, are not comparable. Accordingly, in this
Results of Operations section, after comparing the
three months ended March 31, 2008 with the three months
ended March 31, 2007 and the year ended December 31,
2007 with the year ended December 31, 2006, we compare the
year ended December 31, 2006 with the
174-day
period ended June 23, 2005 and the
233-day
period ended December 31, 2005.
Net sales consist principally of sales of refined fuel and
nitrogen fertilizer products. For the petroleum business, net
sales are mainly affected by crude oil and refined product
prices, changes to the input mix and volume changes caused by
operations. Product mix refers to the percentage of production
represented by higher value light products, such as gasoline,
rather than lower value finished products, such as pet coke. In
the nitrogen fertilizer business, net sales are primarily
impacted by manufactured tons and nitrogen fertilizer prices.
Industry-wide petroleum results are driven and measured by the
relationship, or margin, between refined products and the prices
for crude oil referred to as crack spreads. See
Major Influences on Results of
Operations. We discuss our results of petroleum operations
in the context of per barrel consumed crack spreads and the
relationship between net sales and cost of product sold.
Our consolidated results of operations include certain other
unallocated corporate activities and the elimination of
intercompany transactions and therefore are not a sum of only
the operating results of the petroleum and nitrogen fertilizer
businesses.
In order to effectively review and assess our historical
financial information below, we have also included supplemental
operating measures and industry measures which we believe are
material to understanding our business. For the year ended
December 31, 2005, we have provided this supplemental
information on a combined basis in order to provide a
comparative basis for similar periods of time. As discussed
above, due to the acquisition that occurred, there were two
financial statement periods in the 2005 calendar year of less
than 12 months. We believe that the most meaningful way to
present this supplemental data for the 2005 calendar year is to
compare the sum of the combined operating results for the year
ended December 31, 2005 with the year ended
December 31, 2006. Accordingly, for purposes of displaying
supplemental operating data for the year ended December 31,
2005, we have combined the
174-day
period ended June 23, 2005 and the
233-day
period ended December 31, 2005 to provide a comparative
year ended December 31, 2005 to the year ended
December 31, 2006.
We changed our method of allocating corporate selling, general
and administrative expense to the operating segments in 2007.
The effect of the change on operating income for
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005 and the year ended
December 31, 2006 would have been a decrease of
$1.0 million, $1.4 million and $6.0 million,
respectively, to the petroleum segment, an increase of
$1.2 million, $1.4 million and $6.0 million,
respectively, to the nitrogen fertilizer segment and a decrease
of $0.2 million, $0.0 million and $0.0 million,
respectively, to the other segment.
91
The following table provides an overview of our results of
operations during the past three fiscal years and the three
months ended March 31, 2007 and March 31, 2008:
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Immediate
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Predecessor
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Successor
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174 Days
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233 Days
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Ended
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Ended
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Year Ended
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Year Ended
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Three Months
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June 23,
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December 31,
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December 31,
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December 31,
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Ended March 31,
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Consolidated Financial Results
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2005
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2005
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2006
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2007
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2007
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|
2008
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(unaudited)
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(unaudited)
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(in millions)
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Net sales
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$
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980.7
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$
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1,454.3
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$
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3,037.6
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$
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2,966.9
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$
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390.5
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$
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1,223.0
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Cost of product sold (exclusive of depreciation and amortization)
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768.0
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1,168.1
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2,443.4
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2,308.8
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303.7
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1,036.2
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Direct operating expenses (exclusive of depreciation and
amortization)
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80.9
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85.3
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199.0
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276.1
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113.4
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60.6
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Selling, general and administrative expense (exclusive of
depreciation and amortization)
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18.4
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18.4
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62.6
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93.1
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13.2
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13.4
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Net costs associated with flood(1)
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41.5
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5.8
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Depreciation and amortization(2)
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1.1
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24.0
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51.0
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60.8
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14.2
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19.6
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Operating income
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$
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112.3
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$
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158.5
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$
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281.6
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$
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186.6
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$
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(54.0
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)
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$
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87.4
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Net income (loss)(3)
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52.4
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(119.2
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)
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191.6
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(67.6
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)
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(154.4
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)
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22.2
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Net income (loss) adjusted for
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unrealized gain or loss from Cash Flow Swap(4)
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52.4
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23.6
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115.4
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(5.6
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(137.0
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(47.9
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)
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(1)
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Represents the write-off of
approximate net costs associated with the flood and crude oil
discharge that are not probable of recovery. See Flood and
Crude Oil Discharge.
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(2)
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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:
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Immediate
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Predecessor
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Successor
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174 Days
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233 Days
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Year
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Ended
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Ended
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Ended
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Three Months
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June 23,
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December 31,
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December 31,
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Ended March 31,
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Consolidated Financial Results
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2005
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2005
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2006
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2007
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2007
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2008
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(unaudited)
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(unaudited)
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(in millions)
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Depreciation and amortization excluded from cost of product sold
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$
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0.1
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$
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1.1
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$
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2.2
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$
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2.4
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$
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0.6
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$
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0.6
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Depreciation and amortization excluded from direct operating
expenses
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0.9
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22.7
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47.7
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57.4
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13.5
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18.7
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Depreciation and amortization excluded from selling, general and
administrative expense
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0.1
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0.2
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1.1
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1.0
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0.1
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0.3
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Depreciation included in net costs associated with flood
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7.6
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Total depreciation and amortization
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$
|
1.1
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$
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24.0
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$
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51.0
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$
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68.4
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$
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14.2
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$
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19.6
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92
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(3)
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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:
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Immediate
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Predecessor
|
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Successor
|
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|
174 Days
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|
233 Days
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Year
|
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Ended
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Ended
|
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Ended
|
|
|
Three Months
|
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|
|
June 23,
|
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December 31,
|
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December 31,
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|
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Ended March 31,
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|
Consolidated Financial Results
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
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|
|
|
|
|
|
(unaudited)
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|
(unaudited)
|
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(in millions)
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Loss of extinguishment of debt(a)
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$
|
8.1
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|
$
|
|
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|
$
|
23.4
|
|
|
$
|
1.3
|
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|
$
|
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|
|
$
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|
|
Inventory fair market value adjustment(b)
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|
16.6
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Funded letter of credit expense & interest rate swap
not included in interest expense(c)
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2.3
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|
1.8
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|
|
|
|
|
|
|
0.9
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|
Major scheduled turnaround expense(d)
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|
|
|
|
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6.6
|
|
|
|
76.4
|
|
|
|
66.0
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|
|
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|
Loss on termination of swap(e)
|
|
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|
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|
|
25.0
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|
|
Unrealized (gain) loss from Cash Flow Swap
|
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|
235.9
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|
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(126.8
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)
|
|
|
103.2
|
|
|
|
119.7
|
|
|
|
13.9
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|
|
|
|
(a)
|
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Represents the write-off of
$8.1 million of deferred financing costs in connection with
the refinancing of our senior secured credit facility on
June 23, 2005, the write-off of $23.4 million in
connection with the refinancing of our senior secured credit
facility on December 28, 2006 and the write-off of
$1.3 million in connection with the repayment and
termination of three credit facilities on October 26, 2007.
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(b)
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Consists of the additional cost of
product sold expense due to the step up to estimated fair value
of certain inventories on hand at June 24, 2005, as a
result of the allocation of the purchase price of the Subsequent
Acquisition to inventory.
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(c)
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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.
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(d)
|
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Represents expenses associated with
a major scheduled turnaround at the nitrogen fertilizer plant
and our refinery.
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(e)
|
|
Represents the expense associated
with the expiration of the crude oil, heating oil and gasoline
option agreements entered into by Coffeyville Acquisition LLC in
May 2005.
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(4)
|
|
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap results from
adjusting for the unrealized portion of the derivative
transaction that was executed in conjunction with the Subsequent
Acquisition. On June 16, 2005, Coffeyville Acquisition LLC
entered into the Cash Flow Swap with J. Aron, a subsidiary of
The Goldman Sachs Group, Inc., and a related party of ours. The
Cash Flow Swap was subsequently assigned from Coffeyville
Acquisition LLC to Coffeyville Resources, LLC on June 24,
2005. The derivative took the form of three NYMEX swap
agreements whereby if absolute (i.e., in dollar terms, not as a
percentage of crude oil prices) crack spreads fall below the
fixed level, J. Aron agreed to pay the difference to us, and if
absolute crack spreads rise above the fixed level, we agreed to
pay the difference to J. Aron. The Cash Flow Swap represents
approximately 58% and 14% of crude oil capacity for the periods
July 1, 2008 through June 30, 2009 and July 1,
2009 through June 30, 2010, respectively. Under the terms
of our credit facility and upon meeting specific requirements
related to our leverage ratio and our credit ratings, we are
permitted to reduce the Cash Flow Swap to 35,000 bpd, or
approximately 30% of expected crude oil capacity, for the period
from April 1, 2008 through December 31, 2008 and
terminate the Cash Flow Swap in 2009 and 2010, so long as at the
time of reduction or termination, we pay the amount of
unrealized losses associated with the amount reduced or
terminated.
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We have determined that the Cash
Flow Swap does not qualify as a hedge for hedge accounting
purposes under current GAAP. As a result, our periodic
statements of operations reflect material amounts of unrealized
gains and losses based on the increases or decreases in market
value of the unsettled position under the swap agreements which
is accounted for as a liability on our balance sheet. As the
absolute crack spreads increase we are required to record an
increase in this liability account with a corresponding expense
entry to be made to our statement of operations. Conversely, as
absolute crack spreads decline, we are required to record a
decrease in the swap related liability and post a corresponding
income entry to our statement of operations. Because of this
inverse relationship between the economic outlook for our
underlying business (as represented by crack spread levels) and
the income impact of the unrecognized gains and losses, and
given the significant periodic fluctuations in the amounts of
unrealized gains and losses, management utilizes Net income
(loss) adjusted for unrealized gain or loss from Cash Flow
|
93
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|
|
Swap as a key indicator of our
business performance. In managing our business and assessing its
growth and profitability from a strategic and financial planning
perspective, management and our board of directors considers our
GAAP net income results as well as Net income (loss) adjusted
for unrealized gain or loss from Cash Flow Swap. We believe that
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap enhances the understanding of our results of
operations by highlighting income attributable to our ongoing
operating performance exclusive of charges and income resulting
from mark to market adjustments that are not necessarily
indicative of the performance of our underlying business and our
industry. The adjustment has been made for the unrealized loss
from Cash Flow Swap net of its related tax benefit.
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Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap is not a recognized
term under GAAP and should not be substituted for net income as
a measure of our financial performance or liquidity but instead
should be utilized as a supplemental measure of performance in
evaluating our business. Because Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap excludes mark to
market adjustments, the measure does not reflect the fair market
value of our cash flow swap in our net income. As a result, the
measure does not include potential cash payments that may be
required to be made on the Cash Flow Swap in the future. Also,
our presentation of this non-GAAP measure may not be comparable
to similarly titled measures of other companies.
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The following is a reconciliation of Net income (loss) adjusted
for unrealized gain or loss from Cash Flow Swap to Net income
(loss):
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Immediate
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|
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Predecessor
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Successor
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174 Days
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233 Days
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Year
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Ended
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Ended
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Ended
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Three Months
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June 23,
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December 31,
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December 31,
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Ended March 31,
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Consolidated Financial
Results
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2005
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2005
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2006
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2007
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2007
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|
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2008
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|
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|
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(unaudited)
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(unaudited)
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(in millions)
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Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap
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$
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52.4
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$
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23.6
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$
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115.4
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$
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(5.6
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)
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$
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(82.4
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)
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$
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30.6
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Plus:
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Unrealized gain or (loss) from Cash Flow Swap, net of taxes
|
|
|
|
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(142.8
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)
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|
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76.2
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|
|
|
(62.0
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)
|
|
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(72.0
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)
|
|
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(8.4
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)
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|
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Net income (loss)
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|
$
|
52.4
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$
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(119.2
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)
|
|
$
|
191.6
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|
|
$
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(67.6
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)
|
|
$
|
(154.4
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)
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$
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22.2
|
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Three Months
Ended March 31, 2008 Compared to the Three Months Ended
March 31, 2007 (Consolidated)
Net Sales.
Consolidated net sales were
$1,223.0 million for the three months ended March 31,
2008 compared to $390.5 million for the three months ended
March 31, 2007. The increase of $832.5 million for the
three months ended March 31, 2008 as compared to the three
months ended March 31, 2007 was primarily due to an
increase in petroleum net sales of $816.0 million that
resulted from higher sales volumes ($592.1 million)
primarily resulting from the refinery turnaround which began in
February 2007 and was completed in April 2007 and higher product
prices ($223.9 million). Nitrogen fertilizer net sales
increased $24.0 million for the three months ended
March 31, 2008 as compared to the three months ended
March 31, 2007 primarily due to higher plant gate prices,
partially offset by reductions in overall sales volume.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Consolidated cost of product
sold exclusive of depreciation and amortization was
$1,036.2 million for the three months ended March 31,
2008 as compared to $303.7 million for the three months
ended March 31, 2007. The increase of $732.5 million
for the three months ended March 31, 2008 as compared to
the three months ended March 31, 2007 primarily resulted
from a significant increase in refined fuel production
94
volumes over the comparable period due to the refinery
turnaround which began in February 2007 and was completed in
April 2007.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Consolidated direct operating
expenses exclusive of depreciation and amortization were
$60.6 million for the three months ended March 31,
2008 as compared to $113.4 million for the three months
ended March 31, 2007. This decrease of $52.8 million
for the three months ended March 31, 2008 as compared to
the three months ended March 31, 2007 was due to a decrease
in petroleum direct operating expenses of $56.4 million,
primarily related to decreases in expenses associated with the
refinery turnaround and labor, partially offset by increases in
expenses associated with utilities and energy, repairs and
maintenance, production chemicals, taxes and environmental.
Nitrogen fertilizer direct operating expenses increased during
the comparable period by $3.6 million, primarily due to
increases in expenses associated with taxes, repairs and
maintenance, labor, catalysts and outsides services, partially
offset by decreases in expenses associated with utilities,
royalties and other and equipment rental. The nitrogen
fertilizer facility was subject to a property tax abatement
which expired beginning in 2008. We have estimated our accrued
property tax liability based upon the assessment value received
by the county.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization.
Consolidated
selling, general and administrative expenses were
$13.4 million for the three months ended March 31,
2008 as compared to $13.2 million for the three months
ended March 31, 2007. This variance was primarily the
result of decreases in administrative labor ($3.0 million)
primarily related to deferred compensation which was more than
offset by increases in expenses related to outside services
($2.2 million), bad debt ($0.4 million), insurance
($0.3 million), bank charges ($0.2 million), public
relations ($0.1 million) and other selling, general and
administrative costs ($0.1 million).
Net Costs Associated with
Flood.
Consolidated net costs associated with
flood for the three months ended March 31, 2008
approximated $5.8 million as compared to none for the three
months ended March 31, 2007. As the flood occurred in the
second and third quarter of 2007 there was no financial
statement impact in the first quarter of 2007. Total gross costs
recorded for the three months ended March 31, 2008 were
approximately $7.6 million. Of these gross costs,
approximately $3.8 million were associated with repair and
other matters as a result of the damage to the Companys
facilities. Included in this cost was $0.3 million of
professional fees and $3.5 million for other repair and
related costs. There were also approximately $3.8 million
of costs recorded with respect to environmental remediation and
property damage. Total accounts receivable from insurers
approximated $85.7 million at March 31, 2008, for
which we believe collection is probable.
Depreciation and
Amortization.
Consolidated depreciation and
amortization was $19.6 million for the three months ended
March 31, 2008 as compared to $14.2 million for the
three months ended March 31, 2007. The increase in
depreciation and amortization for the three months ended
March 31, 2008 as compared to the three months ended
March 31, 2007 was primarily the result of the completion
of several large capital projects.
Operating Income.
Consolidated
operating income was $87.4 million for the three months
ended March 31, 2008 as compared to an operating loss of
$54.0 million for the three months ended March 31,
2007. For the three months ended March 31, 2008 as compared
to the three months ended March 31, 2007, petroleum
operating income increased $127.1 million and nitrogen
fertilizer operating income increased by $16.7 million.
Interest Expense.
Consolidated interest
expense for the three months ended March 31, 2008 was
$11.3 million as compared to interest expense of
$11.9 million for the three months ended March 31,
2007. This 5% decrease for the three months ended March 31,
2008 as compared to the three months ended March 31, 2007
primarily resulted from an overall decrease in the index rates
(primarily LIBOR) and a decrease in average borrowings
outstanding during the comparable periods.
95
Interest Income.
Interest income was
$0.7 million for the three months ended March 31, 2008
as compared to $0.5 million for the three months ended
March 31, 2007.
Loss on Derivatives, Net.
We have
determined that the Cash Flow Swap and our other derivative
instruments do not qualify as hedges for hedge accounting
purposes under SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities.
For the three
months ended March 31, 2008, we incurred $47.9 million
in losses on derivatives. This compares to a $137.0 million
loss on derivatives for the three months ended March 31,
2007. This significant decrease in loss on derivatives, net for
the three months ended March 31, 2008 as compared to the
three months ended March 31, 2007 was primarily
attributable to the realized and unrealized losses on our Cash
Flow Swap. Realized losses on the Cash Flow Swap for the three
months ended March 31, 2008 and the three months ended
March 31, 2007 were $21.5 million and
$8.5 million, respectively. The increase in realized losses
over the comparable periods was primarily the result of higher
net barrels hedged for the three months ended March 31,
2008 as compared to the three months ended March 31, 2007.
Unrealized losses represent the change in the mark-to-market
value on the unrealized portion of the Cash Flow Swap based on
changes in the NYMEX crack spread that is the basis for the Cash
Flow Swap. Unrealized losses on our Cash Flow Swap for the three
months ended March 31, 2008 and the three months ended
March 31, 2007 were $13.9 million and
$119.7 million, respectively. This change in the unrealized
loss of the Cash Flow Swap over the comparable periods reflect
decreases in the crack spread values on the unrealized positions
comprising the Cash Flow Swap. In addition to the change in the
NYMEX crack spread, the outstanding term of the Cash Flow Swap
at the end of each period also affects the impact that the
changes of the underlying crack spread may have on the
unrealized gain or loss. As of March 31, 2008, the Cash
Flow Swap had a remaining term of approximately two years and
three months whereas as of March 31, 2007 the remaining
term on the Cash Flow Swap was approximately three years and
three months. As a result of the shorter remaining term as of
March 31, 2008, a similar change in crack spread will have
a smaller impact on the unrealized gains or losses.
Provision for Income Taxes.
Income tax
expense for the three months ended March 31, 2008 was
$6.9 million, or 23.6% of income before income taxes, as
compared to income tax benefit of $(47.3) million, or 23.4%
of earnings before income taxes, for the three months ended
March 31, 2007.
Minority Interest in (Income) Loss of
Subsidiaries.
Minority interest in loss of
subsidiaries for the three months ended March 31, 2007 was
$0.7 million compared to none during the three months ended
March 31, 2008. Minority interest for 2007 related to
common stock in two of our subsidiaries owned by our chief
executive officer. In October 2007, in connection with our
initial public offering, our chief executive officer exchanged
his common stock in our subsidiaries for common stock of CVR
Energy.
Net Income.
For the three months ended
March 31, 2008, net income increased to $22.2 million
as compared to net loss of $(154.4) million for the three
months ended March 31, 2007. Net income increased
$176.6 million compared to the first quarter of 2007
primarily due to the planned turnaround that commenced in
February 2007. For the three months ended March 31, 2007
the Company incurred costs of $66.0 million associated with
the refinery turnaround. In addition the Companys net
income was favorably impacted by a significant change in the
fair value of the Cash Flow Swap over the comparable periods.
Year Ended
December 31, 2007 Compared to the Year Ended
December 31, 2006 (Consolidated).
Net Sales.
Consolidated net sales were
$2,966.9 million for the year ended December 31, 2007
compared to $3,037.6 million for the year ended
December 31, 2006. The decrease of $70.7 million for
the year ended December 31, 2007 as compared to the year
ended December 31, 2006 was primarily due to a decrease in
petroleum net sales of $74.2 million that resulted from
lower
96
sales volumes ($576.9 million), partially offset by higher
product prices ($502.7 million). Nitrogen fertilizer net
sales increased $3.4 million for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 as reductions in overall sales volumes
($31.0 million) were more than offset by higher plant gate
prices ($34.4 million). The sales volume decrease for the
refinery primarily resulted from a significant reduction in
refined fuel production volumes over the comparable periods due
to the refinery turnaround which began in February 2007 and was
completed in April 2007 and the refinery downtime resulting from
the flood. The flood was also a major contributor to lower
nitrogen fertilizer sales volume.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Consolidated cost of product
sold exclusive of depreciation and amortization was
$2,308.8 million for the year ended December 31, 2007
as compared to $2,443.4 million for the year ended
December 31, 2006. The decrease of $134.6 million for
the year ended December 31, 2007 as compared to the year
ended December 31, 2006 primarily resulted from a
significant reduction in refined fuel production volumes over
the comparable periods due to the refinery turnaround which
began in February 2007 and was completed in April 2007 and the
refinery downtime resulting from the flood.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Consolidated direct operating
expenses exclusive of depreciation and amortization were
$276.1 million for the year ended December 31, 2007 as
compared to $199.0 million for the year ended
December 31, 2006. This increase of $77.1 million for
the year ended December 31, 2007 as compared to the year
ended December 31, 2006 was due to an increase in petroleum
direct operating expenses of $74.2 million, primarily
related to the refinery turnaround, and an increase in nitrogen
fertilizer direct operating expenses of $3.0 million.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization.
Consolidated
selling, general and administrative expenses exclusive of
depreciation and amortization were $93.1 million for the
year ended December 31, 2007 as compared to
$62.6 million for the year ended December 31, 2006.
This variance was primarily the result of increases in
administrative labor primarily related to deferred compensation
and share-based compensation ($19.1 million), other costs
primarily related to the termination of the management
agreements with Goldman Sachs Funds and Kelso Funds
($10.6 million), bank charges ($1.3 million) and
office costs ($0.3 million).
Net Costs Associated with
Flood.
Consolidated net costs associated with
flood for the year ended December 31, 2007 approximated
$41.5 million as compared to none for the year ended
December 31, 2006. Total gross costs associated with the
flood for the year ended December 31, 2007 were
approximately $146.8 million. Of these gross costs,
approximately $101.9 million were associated with repair
and other matters as a result of the physical damage to the
Companys facilities and approximately $44.9 million
were associated with the environmental remediation and property
damage. Included in the gross costs associated with the flood
were certain costs that are excluded from the accounts
receivable from insurers of $85.3 million at
December 31, 2007, for which we believe collection is
probable. The costs excluded from the accounts receivable from
insurers were $7.6 million of depreciation for the
temporarily idled facilities, $3.6 million of uninsured
losses within the Companys insurance deductibles,
$6.8 million of uninsured expenses and $23.5 million
recorded with respect to environmental remediation and property
damage. As of December 31, 2007, $20.0 million of
insurance recoveries recorded in 2007 had been collected and are
not reflected in the accounts receivable from insurers balance
at December 31, 2007.
Depreciation and
Amortization.
Consolidated depreciation and
amortization was $60.8 million for the year ended
December 31, 2007 as compared to $51.0 million for the
year ended December 31, 2006. During the restoration period
for the refinery and our nitrogen fertilizer operations due to
the flood, $7.6 million of depreciation and amortization
was reclassified into net costs associated with flood. Adjusting
for this $7.6 million reclassification, the increase in
consolidated depreciation and amortization for the year ended
December 31, 2007 compared to the year ended
December 31, 2006 would have been approximately
$17.4 million. This adjusted increase in consolidated
depreciation and
97
amortization for the year ended December 31, 2007 as
compared to the year ended December 31, 2006 was primarily
the result of the completion of the several large capital
projects in late 2006 and during the year ended
December 31, 2007 in our Petroleum business.
Operating Income.
Consolidated
operating income was $186.6 million for the year ended
December 31, 2007 as compared to operating income of
$281.6 million for the year ended December 31, 2006.
For the year ended December 31, 2007 as compared to the
year ended December 31, 2006, petroleum operating income
decreased $100.7 million primarily as a result of the
refinery turnaround which began in February 2007 and was
completed in April 2007 and the refinery downtime associated
with the flood. For the year ended December 31, 2007 as
compared to the year ended December 31, 2006, nitrogen
fertilizer operating income increased by $9.8 million as
downtime and expenses associated with the flood and increases in
direct operating expenses were more than offset by a reduction
in cost of product sold and higher plant gate prices.
Interest Expense.
Consolidated interest
expense for the year ended December 31, 2007 was
$61.1 million as compared to interest expense of
$43.9 million for the year ended December 31, 2006.
This 39% increase for the year ended December 31, 2007 as
compared to the year ended December 31, 2006 primarily
resulted from an overall increase in the index rates (primarily
LIBOR) and an increase in average borrowings outstanding during
the comparable periods. Partially offsetting these negative
impacts on consolidated interest expense was a $0.4 million
increase in capitalized interest over the comparable periods.
Additionally, consolidated interest expense over the comparable
periods was partially offset by decreases in the applicable
margins under our credit facility dated December 28, 2006
as compared to our prior borrowing facility in effect for
substantially all of the year ended December 31, 2006.
Interest Income.
Interest income was
$1.1 million for the year ended December 31, 2007 as
compared to $3.5 million for the year ended
December 31, 2006.
Gain (loss) on Derivatives.
We have
determined that the Cash Flow Swap and our other derivative
instruments do not qualify as hedges for hedge accounting
purposes under SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities.
For the year
ended December 31, 2007, we incurred $282.0 million in
losses on derivatives. This compares to a $94.5 million
gain on derivatives for the year ended December 31, 2006.
This significant change in gain (loss) on derivatives for the
year ended December 31, 2007 as compared to the year ended
December 31, 2006 was primarily attributable to the
realized and unrealized gains (losses) on our Cash Flow Swap.
Realized losses on the Cash Flow Swap for the year ended
December 31, 2007 and the year ended December 31, 2006
were $157.2 million and $46.8 million, respectively.
The increase in realized losses over the comparable periods was
primarily the result of higher average absolute crack spreads
for the year ended December 31, 2007 as compared to the
year ended December 31, 2006. Unrealized gains or losses
represent the change in the mark-to-market value on the
unrealized portion of the Cash Flow Swap based on changes in the
NYMEX crack spread that is the basis for the Cash Flow Swap.
Unrealized losses on our Cash Flow Swap for the year ended
December 31, 2007 were $103.2 million and reflect an
increase in the crack spread values on the unrealized positions
comprising the Cash Flow Swap. In contrast, the unrealized
portion of the Cash Flow Swap for the year ended
December 31, 2006 reported mark-to-market gains of
$126.8 million and reflect a decrease in the crack spread
values on the unrealized positions comprising the Cash Flow
Swap. In addition, the outstanding term of the Cash Flow Swap at
the end of each period also affects the impact of changes in the
underlying crack spread. As of December 31, 2007, the Cash
Flow Swap had a remaining term of approximately two years and
six months whereas as of December, 2006, the remaining term on
the Cash Flow Swap was approximately three years and six months.
As a result of the longer remaining term as of December 31,
2006, a similar change in crack spread will have a greater
impact on the unrealized gains or losses.
Provision for Income Taxes.
Income tax
benefit for the year ended December 31, 2007 was
$88.5 million, or 57% of loss before income taxes, as
compared to income tax expense of
98
$119.8 million, or 39% of earnings before income taxes, for
the year ended December 31, 2006. Our effective tax rate
increased in the year ended December 31, 2007 as compared
to the year ended December 31, 2006 primarily due to the
impact of the American Jobs Creation Act of 2004, which provides
an income tax credit to small business refiners related to the
production of ultra low sulfur diesel. We recognized an income
tax benefit of approximately $17.3 million in 2007 compared
to $4.5 million in 2006 on a credit of approximately
$26.6 million in 2007 compared to a credit of approximately
$6.9 million in 2006 related to the production of ultra low
sulfur diesel. In addition, state income tax credits, net of
federal expense, approximating $19.8 million were earned
and recorded in 2007 that related to the expansion of the
facilities in Kansas.
Minority Interest in (Income) Loss of
Subsidiaries.
Minority interest in loss of
subsidiaries for the year ended December 31, 2007 was
$0.2 million. Minority interest relates to common stock in
two of our subsidiaries owned by our chief executive officer. In
October 2007, in connection with our initial public offering,
our chief executive officer exchanged his common stock in our
subsidiaries for common stock of CVR Energy.
Net Income.
For the year ended
December 31, 2007, net income decreased to a net loss of
$67.6 million as compared to net income of
$191.6 million for the year ended December 31, 2006.
Net income decreased $259.2 million for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006, primarily due to the refinery
turnaround, downtime and costs associated with the flood and a
significant change in the value of the Cash Flow Swap over the
comparable periods.
Year Ended
December 31, 2006 Compared to the 174 Days Ended
June 23, 2005 and the 233 Days Ended December 31, 2005
(Consolidated).
Net Sales.
Consolidated net sales were
$3,037.6 million for the year ended December 31, 2006
compared to $980.7 million for the 174 days ended
June 23, 2005 and $1,454.3 million for the
233 days ended December 31, 2005. The increase of
$602.6 million for the year ended December 31, 2006 as
compared to the combined periods ended December 31, 2005
was primarily due to an increase in petroleum net sales of
$613.2 million that resulted from significantly higher
product prices ($384.1 million) and increased sales volumes
($229.1 million) over the comparable periods. Nitrogen
fertilizer net sales decreased $10.5 million for the year
ended December 31, 2006 as compared to the combined periods
ended December 31, 2005 due to decreased selling prices
($1.6 million) and a reduction in overall sales volumes
($8.9 million).
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Consolidated cost of product
sold exclusive of depreciation and amortization was
$2,443.4 million for the year ended December 31, 2006
as compared to $768.0 million for the 174 days ended
June 23, 2005 and $1,168.1 million for the
233 days ended December 31, 2005. The increase of
$507.3 million for the year ended December 31, 2006 as
compared to the combined periods ended December 31, 2005
was primarily due to an increase in crude oil prices, sales
volumes and the impact of FIFO accounting in our petroleum
business. The nitrogen fertilizer business accounted for
approximately $2.3 million of the increase in cost of
products sold over the comparable period primarily related to
increases in freight expense.
Depreciation and
Amortization.
Consolidated depreciation and
amortization was $51.0 million for the year ended
December 31, 2006 as compared to $1.1 million for the
174 days ended June 23, 2005 and $24.0 million
for the 233 days ended December 31, 2005. The increase
of $25.9 million for the year ended December 31, 2006
as compared to the combined periods ended December 31, 2005
was due to an increase in petroleum depreciation and
amortization of $16.6 million and an increase in nitrogen
fertilizer depreciation and amortization of $8.4 million.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Consolidated direct operating
expenses exclusive of depreciation and amortization were
$199.0 million for the year ended December 31, 2006 as
compared to $80.9 million for the 174 days ended
June 23, 2005 and
99
$85.3 million for the 233 days ended December 31,
2005. This increase of $32.8 million for the year ended
December 31, 2006 as compared to the combined periods ended
December 31, 2005 was due to an increase in petroleum
direct operating expenses of $26.5 million and an increase
in nitrogen fertilizer direct operating expenses of
$6.2 million.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization.
Consolidated
selling, general and administrative expenses were
$62.6 million for the year ended December 31, 2006 as
compared to $18.4 million for the 174 days ended
June 23, 2005 and $18.4 million for the 233 days
ended December 31, 2005. Consolidated selling, general and
administrative expenses for the 174 days ended
June 23, 2005 were negatively impacted by certain expenses
associated with $3.3 million of unearned compensation
related to the management equity of Immediate Predecessor in
relation to the Subsequent Acquisition. Adjusting for this
expense, consolidated selling, general and administrative
expenses increased $29.1 million for the year ended
December 31, 2006 as compared to the combined periods ended
December 31, 2005. This variance was primarily the result
of increases in administrative labor related to increased
headcount and share-based compensation ($18.6 million),
office costs ($1.3 million), letter of credit fees due
under our $150.0 million funded letter of credit facility
utilized as collateral for the Cash Flow Swap which was not in
place for approximately six months in the comparable period
($2.1 million), public relations expense
($0.5 million) and outside services expense
($2.4 million).
Operating Income.
Consolidated
operating income was $281.6 million for the year ended
December 31, 2006 as compared to $112.3 million for
the 174 days ended June 23, 2005 and
$158.5 million for the 233 days ended
December 31, 2005. For the year ended December 31,
2006 as compared to the combined periods ended December 31,
2005, petroleum operating income increased $45.9 million
and nitrogen fertilizer operating income decreased by
$34.2 million.
Interest Expense.
We reported
consolidated interest expense for the year ended
December 31, 2006 of $43.9 million as compared to
interest expense of $7.8 million for the 174 days
ended June 23, 2005 and $25.0 million for the
233 days ended December 31, 2005. This 34% increase
for the year ended December 31, 2006 as compared to the
combined periods ended December 31, 2005 was the direct
result of increased average borrowings over the comparable
periods associated with both our credit facility dated
December 28, 2006 and our borrowing facility completed in
association with the Subsequent Acquisition and an increase in
the actual rate of our borrowings due primarily to increases
both in index rates (LIBOR and prime rate) and applicable
margins. See Liquidity and Capital
Resources Debt. The comparability of interest
expense during the comparable periods has been impacted by the
differing capital structures of Successor and Immediate
Predecessor periods. See Factors Affecting
Comparability of Our Financial Results.
Interest Income.
Interest income was
$3.5 million for the year ended December 31, 2006 as
compared to $0.5 million for the 174 days ended
June 23, 2005 and $1.0 million for the 233 days
ended December 31, 2005. The increase for the year ended
December 31, 2006 as compared to the combined periods ended
December 31, 2005 was primarily due to larger cash balances
and higher yields on invested cash.
Gain (loss) on Derivatives.
For the
year ended December 31, 2006, we reported
$94.5 million in gains on derivatives. This compares to a
$7.7 million loss on derivatives for the 174 days
ended June 23, 2005 and a $316.1 million loss on
derivatives for the 233 days ended December 31, 2005.
This significant change in gain (loss) on derivatives for the
year ended December 31, 2006 as compared to the combined
period ended December 31, 2005 was primarily attributable
to our Cash Flow Swap and the accounting treatment for all of
our derivative transactions. We determined that the Cash Flow
Swap and our other derivative instruments do not qualify as
hedges for hedge accounting purposes under
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities
. Since the Cash Flow Swap had a
significant term remaining as of December 31, 2006
(approximately three years and six months) and the NYMEX crack
spread that is the basis for the underlying swap contracts that
comprised the Cash Flow Swap had declined during this period,
the unrealized gains on
100
the Cash Flow Swap increased significantly. The
$323.7 million loss on derivatives during the combined
period ended December 31, 2005 is inclusive of the
expensing of a $25.0 million option entered into by
Successor for the purpose of hedging certain levels of refined
product margins. At closing of the Subsequent Acquisition, we
determined that this option was not economical and we allowed
the option to expire worthless, which resulted in the expensing
of the associated premium during the year ended
December 31, 2005. See Quantitative and
Qualitative Disclosures About Market Risk Commodity
Price Risk.
Extinguishment of Debt.
On
December 28, 2006, Coffeyville Acquisition LLC refinanced
its existing first lien credit facility and second lien credit
facility and raised $1.075 billion in long-term debt
commitments under the new credit facility. See
Liquidity and Capital Resources
Debt. As a result of the retirement of the first and
second lien credit facilities with the proceeds of the credit
facility, we recognized $23.4 million as a loss on
extinguishment of debt in 2006. On June 24, 2005 and in
connection with the acquisition of Immediate Predecessor by
Coffeyville Acquisition LLC, we raised $800.0 million in
long-term debt commitments under both the first lien credit
facility and second lien credit facility. See
Factors Affecting Comparability of Our
Financial Results and Liquidity and
Capital Resources Debt. As a result of the
retirement of Immediate Predecessors outstanding
indebtedness consisting of $150.0 million term loan and
revolving credit facilities, we recognized $8.1 million as
a loss on extinguishment of debt in 2005.
Other Income (Expense).
For the year
ended December 31, 2006, other expense was
$0.9 million as compared to other expense of
$0.8 million for the 174 days ended June 23, 2005
and other expense of $0.6 million for the 233 days
ended December 31, 2005.
Provision for Income Taxes.
Income tax
expense for the year ended December 31, 2006 was
$119.8 million, or 38.5% of earnings before income taxes,
as compared to a tax benefit of $26.9 million, or 28.7% of
earnings before income taxes, for the combined periods ended
December 31, 2005. The effective tax rate for 2005 was
impacted by a realized loss on option agreements that expired
unexercised. Coffeyville Acquisition LLC was party to these
agreements and the loss was incurred at that level which we
effectively treated as a permanent non-deductible loss.
Net Income.
For the year ended
December 31, 2006, net income increased to
$191.6 million as compared to net income of
$52.4 million for the 174 days ended June 23,
2005 and a net loss of $119.2 million for the 233 days
ended December 31, 2005. Net income increased
$258.4 million for the year ended December 31, 2006 as
compared to the combined periods ended December 31, 2005,
primarily due to improved operating income in our petroleum
operations and a significant change in the value of the Cash
Flow Swap over the comparable periods.
Petroleum
Business Results of Operations
Refining margin is a measurement calculated as the difference
between net sales and cost of products sold (exclusive of
depreciation and amortization). Refining margin is a non-GAAP
measure that we believe is important to investors in evaluating
our refinerys performance as a general indication of the
amount above our cost of products that we are able to sell
refined products. Each of the components used in this
calculation (net sales and cost of products sold exclusive of
depreciation and amortization) can be taken directly from our
statement of operations. Our calculation of refining margin may
differ from similar calculations of other companies in our
industry, thereby limiting its
101
usefulness as a comparative measure. The following table shows
selected information about our petroleum business including
refining margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Three Months
|
|
|
|
June 23,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Ended March 31,
|
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Petroleum Business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
903.8
|
|
|
$
|
1,363.4
|
|
|
$
|
2,880.4
|
|
|
$
|
2,806.2
|
|
|
$
|
352.5
|
|
|
$
|
1,168.5
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
761.7
|
|
|
|
1,156.2
|
|
|
|
2,422.7
|
|
|
|
2,300.2
|
|
|
|
298.5
|
|
|
|
1,035.1
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
52.6
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
5.5
|
|
Depreciation and amortization
|
|
|
0.8
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit (loss)
|
|
$
|
88.7
|
|
|
$
|
135.4
|
|
|
$
|
289.4
|
|
|
$
|
216.8
|
|
|
$
|
(52.5
|
)
|
|
$
|
72.7
|
|
Plus direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
52.6
|
|
|
|
56.2
|
|
|
|
135.3
|
|
|
|
209.5
|
|
|
|
96.7
|
|
|
|
40.3
|
|
Plus net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.7
|
|
|
|
|
|
|
|
5.5
|
|
Plus depreciation and amortization
|
|
|
0.8
|
|
|
|
15.6
|
|
|
|
33.0
|
|
|
|
43.0
|
|
|
|
9.8
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin
|
|
$
|
142.1
|
|
|
$
|
207.2
|
|
|
$
|
457.7
|
|
|
$
|
506.0
|
|
|
$
|
54.0
|
|
|
$
|
133.4
|
|
Refining margin per crude oil throughput barrel
|
|
$
|
9.28
|
|
|
$
|
11.55
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
Gross profit (loss) per crude oil throughput barrel
|
|
$
|
5.79
|
|
|
$
|
7.55
|
|
|
$
|
8.39
|
|
|
$
|
7.79
|
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel
|
|
$
|
3.44
|
|
|
$
|
3.13
|
|
|
$
|
3.92
|
|
|
$
|
7.52
|
|
|
$
|
22.73
|
|
|
$
|
4.16
|
|
Operating income (loss)
|
|
|
76.7
|
|
|
|
123.0
|
|
|
|
245.6
|
|
|
|
144.9
|
|
|
|
(63.5
|
)
|
|
|
63.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
|
and Successor
|
|
|
|
|
|
|
Combined
|
|
|
Successor
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Three Months
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Ended March 31,
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(dollars per barrel, except as indicated)
|
|
|
Market Indicators
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) crude oil
|
|
$
|
56.70
|
|
|
$
|
66.25
|
|
|
$
|
72.36
|
|
|
$
|
58.27
|
|
|
$
|
97.82
|
|
NYMEX 2-1-1 Crack Spread
|
|
|
11.62
|
|
|
|
10.84
|
|
|
|
13.95
|
|
|
|
12.17
|
|
|
|
11.81
|
|
Crude Oil Differentials:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI less WTS (sour)
|
|
|
4.73
|
|
|
|
5.36
|
|
|
|
5.16
|
|
|
|
4.26
|
|
|
|
4.63
|
|
WTI less Maya (heavy sour)
|
|
|
15.67
|
|
|
|
14.99
|
|
|
|
12.54
|
|
|
|
14.80
|
|
|
|
19.84
|
|
WTI less Dated Brent (foreign)
|
|
|
2.18
|
|
|
|
1.13
|
|
|
|
(0.02
|
)
|
|
|
0.51
|
|
|
|
1.10
|
|
PADD II Group 3 versus NYMEX Basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
(0.53
|
)
|
|
|
1.52
|
|
|
|
3.56
|
|
|
|
(0.54
|
)
|
|
|
(1.46
|
)
|
Heating Oil
|
|
|
3.20
|
|
|
|
7.42
|
|
|
|
7.95
|
|
|
|
8.77
|
|
|
|
3.65
|
|
PADD II Group 3 versus NYMEX Crack:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
10.53
|
|
|
|
12.26
|
|
|
|
18.34
|
|
|
|
12.43
|
|
|
|
4.95
|
|
Heating Oil
|
|
|
15.60
|
|
|
|
18.77
|
|
|
|
21.40
|
|
|
|
20.57
|
|
|
|
20.77
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
|
and Successor
|
|
|
|
|
|
|
Combined
|
|
|
Successor
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Three Months
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Ended March 31,
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(dollars per barrel, except as indicated)
|
|
|
Company Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per barrel profit, margin and expense of crude oil throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin
|
|
$
|
10.50
|
|
|
$
|
13.27
|
|
|
$
|
18.17
|
|
|
$
|
12.69
|
|
|
$
|
13.76
|
|
Gross profit
|
|
$
|
6.74
|
|
|
$
|
8.39
|
|
|
$
|
7.79
|
|
|
$
|
(12.34
|
)
|
|
$
|
7.50
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
3.27
|
|
|
|
3.92
|
|
|
|
7.52
|
|
|
|
22.73
|
|
|
|
4.16
|
|
Per gallon sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
1.61
|
|
|
|
1.88
|
|
|
|
2.20
|
|
|
|
1.59
|
|
|
|
2.45
|
|
Distillate
|
|
|
1.71
|
|
|
|
1.99
|
|
|
|
2.28
|
|
|
|
1.78
|
|
|
|
2.85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor Combined
|
|
|
Successor
|
|
|
Successor
|
|
|
Three Months
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Ended March 31,
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
Selected Company
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
Volumetric Data
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gasoline
|
|
|
45,275
|
|
|
|
43.8
|
|
|
|
48,248
|
|
|
|
44.7
|
|
|
|
37,017
|
|
|
|
42.9
|
|
|
|
23,499
|
|
|
|
43.8
|
|
|
|
59,662
|
|
|
|
47.5
|
|
Total distillate
|
|
|
39,997
|
|
|
|
38.7
|
|
|
|
42,175
|
|
|
|
39.0
|
|
|
|
34,814
|
|
|
|
40.4
|
|
|
|
21,976
|
|
|
|
40.9
|
|
|
|
48,591
|
|
|
|
38.7
|
|
Total other
|
|
|
18,090
|
|
|
|
17.5
|
|
|
|
17,608
|
|
|
|
16.3
|
|
|
|
14,370
|
|
|
|
16.7
|
|
|
|
8,214
|
|
|
|
15.3
|
|
|
|
17,361
|
|
|
|
13.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total all production
|
|
|
103,362
|
|
|
|
100.0
|
|
|
|
108,031
|
|
|
|
100.0
|
|
|
|
86,201
|
|
|
|
100.0
|
|
|
|
53,689
|
|
|
|
100.0
|
|
|
|
125,614
|
|
|
|
100.0
|
|
Crude oil throughput
|
|
|
91,097
|
|
|
|
92.6
|
|
|
|
94,524
|
|
|
|
92.1
|
|
|
|
76,285
|
|
|
|
93.0
|
|
|
|
47,267
|
|
|
|
92.7
|
|
|
|
106,530
|
|
|
|
89.0
|
|
All other inputs
|
|
|
7,246
|
|
|
|
7.4
|
|
|
|
8,067
|
|
|
|
7.9
|
|
|
|
5,780
|
|
|
|
7.0
|
|
|
|
3,716
|
|
|
|
7.3
|
|
|
|
13,197
|
|
|
|
11.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks
|
|
|
98,343
|
|
|
|
100.0
|
|
|
|
102,591
|
|
|
|
100.0
|
|
|
|
82,065
|
|
|
|
100.0
|
|
|
|
50,983
|
|
|
|
100.0
|
|
|
|
119,727
|
|
|
|
100.0
|
|
Crude oil throughput by crude type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet
|
|
|
13,958,567
|
|
|
|
42.0
|
|
|
|
17,481,803
|
|
|
|
50.7
|
|
|
|
18,190,459
|
|
|
|
65.3
|
|
|
|
2,782,136
|
|
|
|
65.4
|
|
|
|
6,573,627
|
|
|
|
67.8
|
|
Light/medium-sour
|
|
|
19,291,951
|
|
|
|
58.0
|
|
|
|
16,695,173
|
|
|
|
48.4
|
|
|
|
6,465,368
|
|
|
|
23.2
|
|
|
|
1,454,878
|
|
|
|
34.2
|
|
|
|
1,785,669
|
|
|
|
18.4
|
|
Heavy sour
|
|
|
|
|
|
|
|
|
|
|
324,312
|
|
|
|
0.9
|
|
|
|
3,188,133
|
|
|
|
11.5
|
|
|
|
17,016
|
|
|
|
0.4
|
|
|
|
1,334,889
|
|
|
|
13.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil throughput
|
|
|
33,250,518
|
|
|
|
100.0
|
|
|
|
34,501,288
|
|
|
|
100.0
|
|
|
|
27,843,960
|
|
|
|
100.0
|
|
|
|
4,254,030
|
|
|
|
100.0
|
|
|
|
9,694,185
|
|
|
|
100.0
|
|
Three Months
Ended March 31, 2008 Compared to the Year Ended
March 31, 2007 (Petroleum Business).
Net Sales.
Petroleum net sales were
$1,168.5 million for the three months ended March 31,
2008 compared to $352.5 million for the three months ended
March 31, 2007. The increase of $816.0 million during
the three months ended March 31, 2008 as compared to the
three months ended March 31, 2007 was primarily the result
of significantly higher sales volumes ($592.1 million) and
higher product prices ($223.9 million). Overall sales
volumes of refined fuels for the three months ended
March 31, 2008 increased 110% as compared to the three
months ended March 31, 2007. The increased sales volume
primarily resulted from a significant increase in refined fuel
production volumes over the comparable periods due to the
refinery turnaround which began in February 2007 and was
completed in April 2007. Our average sales price per gallon for
the three months ended
103
March 31, 2008 for gasoline of $2.45 and distillate of
$2.85 increased by 54% and 60%, respectively, as compared to the
three months ended March 31, 2007.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold includes
cost of crude oil, other feedstocks and blendstocks, purchased
products for resale, transportation and distribution costs.
Petroleum cost of product sold exclusive of depreciation and
amortization was $1,035.1 million for the three months
ended March 31, 2008 compared to $298.5 million for
the three months ended March 31, 2007. The increase of
$736.6 million during the three months ended March 31,
2008 as compared to the three months ended March 31, 2007
was primarily the result of a significant increase in crude
throughput due to refinery downtime from the refinery turnaround
which began in February 2007 and was completed in April 2007. In
addition to the refinery turnaround, higher crude oil prices,
increased sales volumes and the impact of FIFO accounting also
impacted cost of product sold during the comparable periods. Our
average cost per barrel of crude oil consumed for the three
months ended March 31, 2008 was $92.35 compared to $51.98
for the comparable period of 2007, an increase of 78%. Sales
volume of refined fuels increased 110% for the three months
ended March 31, 2008 as compared to the three months ended
March 31, 2007. In addition, under our FIFO accounting
method, changes in crude oil prices can cause fluctuations in
the inventory valuation of our crude oil, work in process and
finished goods, thereby resulting in FIFO inventory gains when
crude oil prices increase and FIFO inventory losses when crude
oil prices decrease. For the three months ended March 31,
2008, we had FIFO inventory gains of $20.0 million compared
to FIFO inventory gains of $5.2 million for the comparable
period of 2007. In 2007, as a result of the flood, our refinery
exceeded the required average annual gasoline sulfur standard as
mandated by our approved hardship waiver with the Environmental
Protection Agency (EPA). In anticipation of a
settlement with the EPA to resolve the non-compliance, we
accrued a liability of approximately $3.5 million in the
fourth quarter of 2007. During 2008, the matter was resolved
with the EPA, and accordingly, the liability was reversed
resulting in a reduction to cost of product sold (exclusive of
depreciation and amortization) of approximately
$3.5 million in the first quarter of 2008.
Refining margin per barrel of crude throughput increased from
$12.69 for the three months ended March 31, 2007 to $13.76
for the three months ended March 31, 2008. Gross profit per
barrel increased to $7.50 in the first quarter of 2008, up from
a loss of $(12.34) in the equivalent period in 2007. The primary
contributors to the positive variance in refining margin per
barrel of crude throughput were an increase in FIFO inventory
gains and increases in crude oil differentials over the
comparable periods. Increased discounts for sour crude oils
evidenced by the $0.37 per barrel, or 9%, increase in the spread
between the WTI price, which is a market indicator for the price
of light sweet crude, and the WTS price, which is an indicator
for the price of sour crude, positively impacted refining margin
for the three months ended March 31, 2008 as compared to
the three months ended March 31, 2007. Partially offsetting
the positive effects of FIFO inventory gains and crude oil
differentials was the 3% decrease ($0.36 per barrel) in the
average NYMEX 2-1-1 crack spread over the comparable periods and
negative regional differences between gasoline prices in our
primary marketing region (the mid-continent area) and those of
the NYMEX. The average gasoline basis for the three months ended
March 31, 2008 decreased by $0.92 per barrel to ($1.46) per
barrel compared to ($0.54) per barrel in the comparable period
of 2007. The average distillate basis decreased by $5.12 per
barrel to $3.65 per barrel compared to $8.77 per barrel in the
comparable period of 2007.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
our petroleum operations include costs associated with the
actual operations of our refinery, such as energy and utility
costs, catalyst and chemical costs, repairs and maintenance
(turnaround), labor and environmental compliance costs.
Petroleum direct operating expenses exclusive of depreciation
and amortization were $40.3 million for the three months
ended March 31, 2008 compared to direct operating expenses
of $96.7 million for the three months ended March 31,
2007. The decrease of $56.4 million for the three months
ended March 31, 2008 compared to the three months ended
March 31, 2007 was the result of decreases in expenses
associated with refinery turnaround ($66.0 million) and
direct labor ($1.7 million). These decreases in direct
operating
104
expenses were partially offset by increases in expenses
associated with utilities and energy ($4.3 million),
repairs and maintenance ($3.0 million), production
chemicals ($2.1 million), property taxes
($0.8 million) and environmental ($0.5 million). On a
per barrel of crude throughput basis, direct operating expenses
per barrel of crude oil throughput for the three months ended
March 31, 2008 decreased to $4.16 per barrel as compared to
$22.73 per barrel for the three months ended March 31, 2007
principally due to the 2007 downtime at the refinery for planned
major maintenance and the corresponding impact on overall crude
oil throughput and production volume.
Net Costs Associated with
Flood.
Petroleum net costs associated with
flood for the three months ended March 31, 2008
approximated $5.5 million. As the flood occurred in the
second and third quarter of 2007, there were no flood related
costs incurred in the first quarter of 2007. Total gross costs
recorded for the three months ended March 31, 2008 were
approximately $6.8 million. Of these gross costs
approximately $3.0 million were associated with repair and
other matters as a result of the physical damage to the refinery
and approximately $3.8 million were associated with the
environmental remediation and property damage. Total accounts
receivable from insurers approximated $81.2 million at
March 31, 2008, for which we believe collection is probable.
Depreciation and
Amortization.
Petroleum depreciation and
amortization was $14.9 million for the three months ended
March 31, 2008 as compared to $9.8 million for the
three months ended March 31, 2007. This increase in
petroleum depreciation and amortization for the three months
ended March 31, 2008 as compared to the three months ended
March 31, 2007 was primarily the result of the completion
of several large capital projects.
Operating Income (Loss).
Petroleum
operating income was $63.6 million for the three months
ended March 31, 2008 as compared to an operating loss of
$63.5 million for the three months ended March 31,
2007. This increase of $127.1 million from the three months
ended March 31, 2008 as compared to the three months ended
March 31, 2007 was primarily the result of the refinery
turnaround which began in February 2007 and was completed in
April 2007 and decreases in expenses associated with refinery
turnaround ($66.0 million) and direct labor
($1.7 million). These decreases in direct operating
expenses were partially offset by increases in expenses
associated with utilities and energy ($4.3 million),
repairs and maintenance ($3.0 million), production
chemicals ($2.1 million), taxes ($0.8 million) and
environmental ($0.5 million).
Year Ended
December 31, 2007 Compared to the Year Ended
December 31, 2006 (Petroleum Business).
Net Sales.
Petroleum net sales were
$2,806.2 million for the year ended December 31, 2007
compared to $2,880.4 million for the year ended
December 31, 2006. The decrease of $74.2 million from
the year ended December 31, 2007 as compared to the year
ended December 31, 2006 was primarily the result of
significantly lower sales volumes ($576.9 million),
partially offset by higher product prices ($502.7 million).
Overall sales volumes of refined fuels for the year ended
December 31, 2007 decreased 18% as compared to the year
ended December 31, 2006. The decreased sales volume
primarily resulted from a significant reduction in refined fuel
production volumes over the comparable periods due to the
refinery turnaround which began in February 2007 and was
completed in April 2007 and the refinery downtime resulting from
the flood. Our average sales price per gallon for the year ended
December 31, 2007 for gasoline of $2.20 and distillate of
$2.28 increased by 17% and 15%, respectively, as compared to the
year ended December 31, 2006.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold includes
cost of crude oil, other feedstocks and blendstocks, purchased
products for resale, transportation and distribution costs.
Petroleum cost of product sold exclusive of depreciation and
amortization was $2,300.2 million for the year ended
December 31, 2007 compared to $2,422.7 million for the
year ended December 31, 2006. The decrease of
$122.5 million from the year ended December 31, 2007
as compared to the year ended December 31, 2006 was
primarily the result of a significant reduction in crude
throughput due to the refinery turnaround which began in
February 2007 and was completed
105
in April 2007 and the refinery downtime resulting from the
flood. In addition to the refinery turnaround and the flood,
crude oil prices, reduced sales volumes and the impact of FIFO
accounting also impacted cost of product sold during the
comparable periods. Our average cost per barrel of crude oil for
the year ended December 31, 2007 was $70.06, compared to
$61.71 for the comparable period of 2006, an increase of 14%.
Sales volume of refined fuels decreased 18% for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 principally due to the refinery
turnaround and flood. In addition, under our FIFO accounting
method, changes in crude oil prices can cause fluctuations in
the inventory valuation of our crude oil, work in process and
finished goods, thereby resulting in FIFO inventory gains when
crude oil prices increase and FIFO inventory losses when crude
oil prices decrease. For the year ended December 31, 2007,
we had FIFO inventory gains of $70.5 million compared to
FIFO inventory losses of $7.6 million for the comparable
period of 2006.
Refining margin per barrel of crude throughput increased from
$13.27 for the year ended December 31, 2006 to $18.17 for
the year ended December 31, 2007 primarily due to the 29%
increase ($3.11 per barrel) in the average NYMEX 2-1-1 crack
spread over the comparable periods and positive regional
differences between gasoline and distillate prices in our
primary marketing region (the mid-continent region) and those of
the NYMEX. The average gasoline basis for the year ended
December 31, 2007 increased by $2.04 per barrel to $3.56
per barrel compared to $1.52 per barrel in the comparable period
of 2006. The average distillate basis for the year ended
December 31, 2007 increased by $0.53 per barrel to $7.95
per barrel compared to $7.42 per barrel in the comparable period
of 2006. The positive effect of the increased NYMEX 2-1-1 crack
spreads and refined fuels basis over the comparable periods was
partially offset by reductions in the crude oil differentials
over the comparable periods. Decreased discounts for sour crude
oils evidenced by the $0.20 per barrel, or 4%, decrease in the
spread between the WTI price, which is a market indicator for
the price of light sweet crude, and the WTS price, which is an
indicator for the price of sour crude, negatively impacted
refining margin for the year ended December 31, 2007 as
compared to the year ended December 31, 2006.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
our petroleum operations include costs associated with the
actual operations of our refinery, such as energy and utility
costs, catalyst and chemical costs, repairs and maintenance
(turnaround), labor and environmental compliance costs.
Petroleum direct operating expenses exclusive of depreciation
and amortization were $209.5 million for the year ended
December 31, 2007 compared to direct operating expenses of
$135.3 million for the year ended December 31, 2006.
The increase of $74.2 million for the year ended
December 31, 2007 compared to the year ended
December 31, 2006 was the result of increases in expenses
associated with repairs and maintenance related to the refinery
turnaround ($67.3 million), taxes ($9.3 million),
direct labor ($5.0 million), insurance ($2.4 million),
production chemicals ($0.8 million) and outside services
($0.7 million). These increases in direct operating
expenses were partially offset by reductions in expenses
associated with energy and utilities ($5.8 million), rent
and lease ($2.4 million), environmental compliance
($1.4 million), operating materials ($0.8 million) and
repairs and maintenance ($0.3 million). On a per barrel of
crude throughput basis, direct operating expenses per barrel of
crude throughput for the year ended December 31, 2007
increased to $7.52 per barrel as compared to $3.92 per barrel
for the year ended December 31, 2006 principally due to
refinery turnaround expenses and the related downtime associated
with the turnaround and the flood and the corresponding impact
on overall crude oil throughput and production volume.
Net Costs Associated with
Flood.
Petroleum net costs associated with
the flood for the year ended December 31, 2007 approximated
$36.7 million as compared to none for the year ended
December 31, 2006. Total gross costs recorded for the year
ended December 31, 2007 were approximately
$138.0 million. Of these gross costs approximately
$93.1 million were associated with repair and other matters
as a result of the physical damage to the refinery and
approximately $44.9 million were associated with the
environmental remediation and property damage. Included in
106
the gross costs associated with the flood were certain costs
that are excluded from the accounts receivable from insurers of
$81.4 million at December 31, 2007, for which we
believe collection is probable. The costs excluded from the
accounts receivable from insurers were approximately
$6.8 million recorded for depreciation for the temporarily
idle facilities, $3.5 million of uninsured losses inside of
the Companys deductibles, $2.8 million of uninsured
expenses and $23.5 million recorded with respect to
environmental remediation and property damage. As of
December 31, 2007, $20.0 million of insurance
recoveries recorded in 2007 had been collected and are not
reflected in the accounts receivable from insurers balance at
December 31, 2007.
Depreciation and
Amortization.
Petroleum depreciation and
amortization was $43.0 million for the year ended
December 31, 2007 as compared $33.0 million for the
year ended December 31, 2006, an increase of
$10.0 million over the comparable periods. During the
restoration period for the refinery due to the flood,
$6.8 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $6.8 million reclassification, the increase in
petroleum depreciation and amortization for the year ended
December 31, 2007 compared to the year ended
December 31, 2006 would have been approximately
$16.8 million. This adjusted increase in petroleum
depreciation and amortization for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 was primarily the result of the
completion of the several large capital projects in late 2006
and during the year ended December 31, 2007.
Operating Income (Loss).
Petroleum
operating income was $144.9 million for the year ended
December 31, 2007 as compared to operating income of
$245.6 million for the year ended December 31, 2006.
This decrease of $100.7 million from the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 was primarily the result of the refinery
turnaround which began in February 2007 and was completed in
April 2007 and the refinery downtime resulting from the flood.
The turnaround negatively impacted daily refinery crude
throughput and refined fuels production. Substantially all of
the refinerys units damaged by the flood were back in
operation by August 20, 2007. In addition, direct operating
expenses increased substantially during the year ended
December 31, 2007 related to refinery turnaround
($67.3 million), taxes ($9.3 million), direct labor
($5.0 million), insurance ($2.4 million), production
chemicals ($0.8 million) and outside services
($0.7 million). These increases in direct operating
expenses were partially offset by reductions in expenses
associated with energy and utilities ($5.8 million), rent
and lease ($2.4 million), environmental compliance
($1.4 million), operating materials ($0.8 million) and
repairs and maintenance ($0.3 million).
Year Ended
December 31, 2006 Compared to the 174 Days Ended
June 23, 2005 and the 233 Days Ended December 31, 2005
(Petroleum Business).
Net Sales.
Petroleum net sales were
$2,880.4 million for the year ended December 31, 2006
compared to $903.8 million for the 174 days ended
June 23, 2005 and $1,363.4 million for the
233 days ended December 31, 2005. The increase of
$613.2 million from the year ended December 31, 2006
as compared to the combined periods for the year ended
December 31, 2005 resulted from significantly higher
product prices ($384.1 million) and increased sales volumes
($229.1 million) over the comparable periods. Our average
sales price per gallon for the year ended December 31, 2006
for gasoline of $1.88 and distillate of $1.99 increased by 17%
and 16%, respectively, as compared to the year ended
December 31, 2005. Overall sales volumes of refined fuels
for the year ended December 31, 2006 increased 9% as
compared to the year ended December 31, 2005. The increased
sales volume primarily resulted from higher production levels of
refined fuels during the year ended December 31, 2006 as
compared to the same period in 2005 because of our increased
focus on process unit maximization and lower production levels
in 2005 due to a scheduled reformer regeneration and minor
maintenance in the coker unit and one of our crude units.
Definitions of the terms coker unit and crude unit are contained
in the section of this prospectus entitled Glossary of
Selected Terms.
107
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold includes
cost of crude oil, other feedstocks and blendstocks, purchased
products for resale, transportation and distribution costs.
Petroleum cost of product sold exclusive of depreciation and
amortization was $2,422.7 million for the year ended
December 31, 2006 compared to $761.7 million for the
174 days ended June 23, 2005 and $1,156.2 million
for the 233 days ended December 31, 2005. The increase
of $504.8 million from the year ended December 31,
2006 as compared to the combined periods for the year ended
December 31, 2005 was primarily the result of higher crude
oil prices, increased sales volumes and the impact of FIFO
accounting. Our average cost per barrel of crude oil for the
year ended December 31, 2006 was $61.71, compared to $53.42
for the comparable period of 2005, an increase of 16%. Crude oil
prices increased on average by 17% during the year ended
December 31, 2006 as compared to the comparable period of
2005 due to the residual impact of Hurricanes Katrina and Rita
on the refining sector, geopolitical concerns and strong demand
for refined products. Sales volume of refined fuels increased 9%
for the year ended December 31, 2006 as compared to the
year ended December 31, 2005. In addition, under our FIFO
accounting method, changes in crude oil prices can cause
significant fluctuations in the inventory valuation of our crude
oil, work in process and finished goods, thereby resulting in
FIFO inventory gains when crude oil prices increase and FIFO
inventory losses when crude oil prices decrease. For the year
ended December 31, 2006, we reported FIFO inventory loss of
$7.6 million compared to FIFO inventory gains of
$18.6 million for the comparable period of 2005.
Refining margin per barrel of crude throughput increased from
$10.50 for the year ended December 31, 2005 to $13.27 for
the year ended December 31, 2006, due to increased discount
for sour crude oils demonstrated by the $0.63, or 13%, increase
in the spread between the WTI price, which is a market indicator
for the price of light sweet crude, and the WTS price, which is
an indicator for the price of sour crude, for the year ended
December 31, 2006 as compared to the year ended
December 31, 2005. In addition, positive regional
differences between refined fuel prices in our primary marketing
region (the mid-continent region) and those of the NYMEX, known
as basis, significantly contributed to the increase in our
consumed crack spread in the year ended December 31, 2006
as compared to the year ended December 31, 2005. The
average distillate basis for the year ended December 31,
2006 increased by $4.22 per barrel to $7.42 per barrel compared
to $3.20 per barrel in the comparable period of 2005. The
average gasoline basis for the year ended December 31, 2006
increased by $2.05 per barrel to $1.52 per barrel in comparison
to a negative basis of $0.53 per barrel in the comparable period
of 2005.
Depreciation and
Amortization.
Petroleum depreciation and
amortization was $33.0 million for the year ended
December 31, 2006 as compared $0.8 million for the
174 days ended June 23, 2005 and $15.6 million
for the 233 days ended December 31, 2005. The increase
of $16.6 million for the year ended December 31, 2006
compared to the combined periods for the year ended
December 31, 2005 was primarily the result of the
step-up
in
our property, plant and equipment for the Subsequent
Acquisition. See Factors Affecting
Comparability of Our Financial Results.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
our petroleum operations include costs associated with the
actual operations of our refinery, such as energy and utility
costs, catalyst and chemical costs, repairs and maintenance,
labor and environmental compliance costs. Petroleum direct
operating expenses exclusive of depreciation and amortization
were $135.3 million for the year ended December 31,
2006 compared to direct operating expenses of $52.6 million
for the 174 days ended June 23, 2005 and
$56.2 million for the 233 days ended December 31,
2005. The increase of $26.5 million for the year ended
December 31, 2006 compared to the combined periods for the
year ended December 31, 2005 was the result of increases in
expenses associated with direct labor ($3.3 million), rent
and lease ($2.3 million), environmental compliance
($1.9 million), operating materials ($1.2 million),
repairs and maintenance ($7.7 million), major scheduled
turnaround ($4.0 million), chemicals ($3.0 million),
insurance $(1.3 million) and outside services
($1.4 million). On a per barrel of crude throughput basis,
direct operating
108
expenses per barrel of crude throughput for the year ended
December 31, 2006 increased to $3.92 per barrel as compared
to $3.27 per barrel for the year ended December 31, 2005.
Operating Income.
Petroleum operating
income was $245.6 million for the year ended
December 31, 2006 as compared to $76.7 million for the
174 days ended June 23, 2005 and $123.0 million
for the 233 days ended December 31, 2005 This increase
of $45.9 million from the year ended December 31, 2006
as compared to the combined periods for the year ended
December 31, 2005 primarily resulted from higher refining
margins due to improved crude differentials and strong gasoline
and distillate basis during the comparable periods. The increase
in operating income was somewhat offset by expenses associated
with direct labor ($3.3 million), rent and lease
($2.3 million), environmental compliance
($1.9 million), operating materials ($1.2 million),
repairs and maintenance ($7.7 million), major scheduled
turnaround ($4.0 million), chemicals ($3.0 million),
insurance ($1.3 million), outside services
($1.4 million) and depreciation and amortization
($16.6 million).
Nitrogen
Fertilizer Business Results of Operations
The tables below provide an overview of the nitrogen fertilizer
business results of operations, relevant market indicators
and its key operating statistics during the past three years:
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|
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|
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Immediate
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|
|
|
|
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Predecessor
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|
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Successor
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174 Days
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|
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233 Days
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Year
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|
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Ended
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Ended
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Ended
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Three Months
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June 23,
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December 31,
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December 31,
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Ended March 31,
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Nitrogen Fertilizer Business Financial Results
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2005
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2005
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|
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2006
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|
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2007
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|
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2007
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2008
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(unaudited)
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(unaudited)
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(in millions)
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Net sales
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$
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79.3
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$
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93.7
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|
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$
|
162.5
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|
|
$
|
165.9
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|
|
$
|
38.6
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|
|
$
|
62.6
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Cost of product sold (exclusive of depreciation and amortization)
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9.1
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14.5
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25.9
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13.0
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6.1
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|
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8.9
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|
Direct operating expenses (exclusive of depreciation and
amortization)
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28.3
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|
|
29.2
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|
63.7
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|
|
|
66.7
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16.7
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20.3
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Net costs associated with flood
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2.4
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Depreciation and amortization
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0.3
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|
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8.4
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|
|
17.1
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|
|
|
16.8
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4.4
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4.5
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Operating income
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35.3
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|
|
35.7
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|
|
|
36.8
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|
|
|
46.6
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|
|
|
9.3
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|
|
|
26.0
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|
|
|
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Year Ended December 31,
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Three Months Ended March 31,
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Market Indicators
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2005
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|
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2006
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|
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2007
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|
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2007
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|
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2008
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|
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Natural gas (dollars per MMBtu)
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|
$
|
9.01
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|
|
$
|
6.98
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|
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$
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7.12
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$
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7.17
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$
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8.74
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Ammonia Southern Plains (dollars per ton)
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|
356
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|
|
|
353
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|
|
|
409
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|
|
|
389
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|
|
|
590
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UAN Corn Belt (dollars per ton)
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|
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212
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|
|
197
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|
|
|
288
|
|
|
|
239
|
|
|
|
371
|
|
109
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|
|
|
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|
|
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Immediate
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Predecessor
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and Successor
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Combined
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Successor
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Year Ended
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Year Ended
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Year Ended
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|
|
|
|
|
|
December 31,
|
|
|
December 31,
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|
December 31,
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|
Three Months Ended March 31,
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Company Operating Statistics
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2005
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2006
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2007
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2007
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2008
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|
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Production (thousand tons):
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|
|
|
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Ammonia
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|
|
413.2
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|
|
369.3
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|
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326.7
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|
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86.2
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|
|
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83.7
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UAN
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663.3
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633.1
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|
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576.9
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|
|
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165.7
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|
|
|
150.1
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
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|
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1,076.5
|
|
|
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1,002.4
|
|
|
|
903.6
|
|
|
|
251.9
|
|
|
|
233.8
|
|
Sales (thousand tons)(1):
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|
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|
|
|
|
|
|
|
|
|
|
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|
|
|
|
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Ammonia
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141.8
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117.3
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92.1
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20.7
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24.1
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UAN
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646.5
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645.5
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555.4
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166.8
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158.0
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|
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Total
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|
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788.3
|
|
|
|
762.8
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|
|
|
647.5
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|
|
|
187.5
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|
|
|
182.1
|
|
Product pricing (plant gate) (dollars per ton)(1):
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Ammonia
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$
|
324
|
|
|
$
|
338
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|
|
$
|
376
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|
|
$
|
347
|
|
|
$
|
494
|
|
UAN
|
|
$
|
173
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|
$
|
162
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$
|
211
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$
|
169
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|
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$
|
262
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|
On-stream factor(2):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasifier
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|
|
98.1
|
%
|
|
|
92.5
|
%
|
|
|
90.0
|
%
|
|
|
91.8
|
%
|
|
|
91.8
|
%
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Ammonia
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|
|
96.7
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%
|
|
|
89.3
|
%
|
|
|
87.7
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%
|
|
|
86.3
|
%
|
|
|
90.7
|
%
|
UAN
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|
|
94.3
|
%
|
|
|
88.9
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%
|
|
|
78.7
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%
|
|
|
89.4
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%
|
|
|
85.9
|
%
|
Reconciliation to net sales (dollars in thousands):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Freight in revenue
|
|
$
|
15,010
|
|
|
$
|
17,890
|
|
|
$
|
13,826
|
|
|
$
|
3,139
|
|
|
$
|
4,022
|
|
Hydrogen revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,291
|
|
Sales net plant gate
|
|
|
157,989
|
|
|
|
144,575
|
|
|
|
152,030
|
|
|
|
35,436
|
|
|
|
53,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net sales
|
|
$
|
172,999
|
|
|
$
|
162,465
|
|
|
$
|
165,856
|
|
|
$
|
38,575
|
|
|
$
|
62,600
|
|
|
|
|
(1)
|
|
Plant gate sales per ton represents
net sales less freight revenue divided by product sales volume
in tons in the reporting period. Plant gate price per ton is
shown in order to provide a pricing measure that is comparable
across the fertilizer industry.
|
|
(2)
|
|
On-stream factor is the total
number of hours operated divided by the total number of hours in
the reporting period. Excluding the impact of turnarounds at the
fertilizer facility in the third quarter of 2006, the on-stream
factors for the year ended December 31, 2006 would have
been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN.
Excluding the impact of the flood during the weekend of
June 30, 2007, the on-stream factors for the year ended
December 31, 2007 would have been 94.6% for gasifier, 92.4%
for ammonia and 83.9% for UAN.
|
Three Months
Ended March 31, 2008 compared to the Three Months Ended
March 31, 2007 (Nitrogen Fertilizer
Business).
Net Sales.
Nitrogen fertilizer net
sales were $62.6 million for the three months ended
March 31, 2008 compared to $38.6 million for the three
months ended March 31, 2007. The increase of
$24.0 million for the three months ended March 31,
2008 as compared to the three months ended March 31, 2007
was the result of higher plant gate prices, together with a
change in intercompany accounting for hydrogen from cost of
product sold (exclusive of depreciation and amortization) to net
sales over the comparable periods, which eliminates in
consolidation, partially offset by reductions in overall sales
volume.
In regard to product sales volumes for the three months ended
March 31, 2008, our nitrogen fertilizer operations
experienced an increase of 17% in ammonia sales unit volumes and
a decrease of 5% in UAN sales unit volumes. On-stream factors
(total number of hours operated divided by total hours in the
reporting period) for the gasification unit were unchanged over
the comparable periods. On-stream factors for the ammonia unit
were greater than the three months ended March 31, 2007.
On-stream factors for the UAN plant were lower than the three
month period ended March 31, 2007. During the three months
ended March 31, 2008, all three primary nitrogen fertilizer
units experienced approximately five days of downtime associated
with repairs to the air separation unit. It is typical to
110
experience brief outages in complex manufacturing operations
such as our nitrogen fertilizer plant which result in less than
one hundred percent on-stream availability for one or more
specific units.
Plant gate prices are prices FOB the delivery point less any
freight cost we absorb to deliver the product. We believe plant
gate price is meaningful because we sell products both FOB our
plant gate (sold plant) and FOB the customers designated
delivery site (sold delivered) and the percentage of sold plant
versus sold delivered can change month to month or three months
to three months. The plant gate price provides a measure that is
consistently comparable period to period. Plant gate prices for
the three months ended March 31, 2008 for ammonia and UAN
were greater than plant gate prices for the comparable period of
2007 by 43% and 55%, respectively. This dramatic increase in
nitrogen fertilizer prices was not the direct result of an
increase in natural gas prices, but rather the result of
increased demand for nitrogen-based fertilizers due to the
increased use of corn for the production of ethanol and an
overall increase in prices for corn, wheat and soybeans, the
primary row crops in our region. This increase in demand for
nitrogen-based fertilizer has created an environment in which
nitrogen fertilizer prices have disconnected from their
traditional correlation to natural gas prices.
The demand for fertilizer is affected by the aggregate crop
planting decisions and fertilizer application rate decisions of
individual farmers. Individual farmers make planting decisions
based largely on the prospective profitability of a harvest,
while the specific varieties and amounts of fertilizer they
apply depend on factors like crop prices, their current
liquidity, soil conditions, weather patterns and the types of
crops planted.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold exclusive
of depreciation and amortization is primarily comprised of pet
coke expense and freight and distribution expenses. Cost of
product sold (excluding depreciation and amortization) for the
three months ended March 31, 2008 was $8.9 million
compared to $6.1 million for the three months ended
March 31, 2007. The increase of $2.8 million for the
three months ended March 31, 2008 as compared to the three
months ended March 31, 2007 was primarily the result of a
change in accounting for hydrogen reimbursement. For the three
months ended March 31, 2007, hydrogen reimbursement was
included in cost of product sold (exclusive of depreciation and
amortization). For the three months ended March 31, 2008,
hydrogen has been included in net sales. These amounts eliminate
in consolidation. Hydrogen is transferred from our nitrogen
fertilizer operations to our petroleum operations to facilitate
sulfur recovery in the ultra low sulfur diesel production unit.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
our nitrogen fertilizer operations include costs associated with
the actual operations of our nitrogen plant, such as repairs and
maintenance, energy and utility costs, catalyst and chemical
costs, outside services, labor and environmental compliance
costs. Nitrogen direct operating expenses exclusive of
depreciation and amortization for the three months ended
March 31, 2008 were $20.3 million as compared to
$16.7 million for the three months ended March 31,
2007. The increase of $3.6 million for the three months
ended March 31, 2008 as compared to the three months ended
March 31, 2007 was primarily the result of increases in
expenses associated with property taxes ($2.5 million),
repairs and maintenance ($1.7 million), labor
($0.3 million), catalysts ($0.3 million) and outside
services ($0.2 million). These increases in direct
operating expenses were partially offset by decreases in
expenses associated with utilities ($0.6 million),
royalties and other ($0.4 million) and equipment rental
($0.3 million).
Depreciation and Amortization.
Nitrogen
fertilizer depreciation and amortization increased to
$4.5 million for the three months ended March 31, 2008
as compared to $4.4 million for the three months ended
March 31, 2007. Nitrogen fertilizer depreciation and
amortization increased by approximately $0.1 million for
the three months ended March 31, 2008 compared to the three
months ended March 31, 2007.
Operating Income.
Nitrogen fertilizer
operating income was $26.0 million for the three months
ended March 31, 2008 as compared to operating income of
$9.3 million for the three months ended March 31,
2007. This increase of $16.7 million for the three months
ended March 31, 2008 as
111
compared to the three months ended March 31, 2007 was
primarily the result of increased fertilizer prices over the
comparable periods. Additionally, decreased direct operating
expenses associated with utilities ($0.6 million),
royalties and other ($0.4 million) and equipment rental
($0.3 million) also contributed to the positive operating
income comparison over the comparable periods. These decreases
in expenses were partially offset by reduced sales volumes and
increased direct operating expenses primarily the result of
increases in taxes ($2.5 million), repairs and maintenance
($1.7 million), labor ($0.3 million), catalysts
($0.3 million) and outside services ($0.2 million).
Year Ended
December 31, 2007 compared to the Year Ended
December 31, 2006 (Nitrogen Fertilizer
Business).
Net Sales.
Nitrogen fertilizer net
sales were $165.9 million for the year ended
December 31, 2007 compared to $162.5 million for the
year ended December 31, 2006. The increase of
$3.4 million from the year ended December 31, 2007 as
compared to the year ended December 31, 2006 was the result
of reductions in overall sales volumes ($31.0 million)
which were more than offset by higher plant gate prices
($34.4 million).
In regard to product sales volumes for the year ended
December 31, 2007, our nitrogen operations experienced a
decrease of 22% in ammonia sales unit volumes (25,283 tons) and
a decrease of 14% in UAN sales unit volumes (90,095 tons). The
decrease in ammonia sales volume was the result of decreased
production volumes during the year ended December 31, 2007
relative to the comparable period of 2006 due to unscheduled
downtime at our fertilizer plant and the transfer of hydrogen to
our petroleum operations to facilitate sulfur recovery in the
ultra low sulfur diesel production unit. The transfer of
hydrogen to our petroleum operations will decrease, to some
extent during 2008 because the new continuous catalytic reformer
will produce hydrogen.
On-stream factors (total number of hours operated divided by
total hours in the reporting period) for all units of our
nitrogen operations (gasifier, ammonia plant and UAN plant) were
less than the comparable period primarily due to approximately
eighteen days of downtime for all three primary nitrogen units
associated with the flood, nine days of downtime related to
compressor repairs in the ammonia unit and 24 days of
downtime related to the UAN expander in the UAN unit. In
addition, all three primary units also experienced brief and
unscheduled downtime for repairs and maintenance during the year
ended December 31, 2007. It is typical to experience brief
outages in complex manufacturing operations such as our nitrogen
fertilizer plant which result in less than one hundred percent
on-stream availability for one or more specific units.
Plant gate prices are prices FOB the delivery point less any
freight cost we absorb to deliver the product. We believe plant
gate price is meaningful because we sell products both FOB our
plant gate (sold plant) and FOB the customers designated
delivery site (sold delivered) and the percentage of sold plant
versus sold delivered can change month to month or year to year.
The plant gate price provides a measure that is consistently
comparable period to period. Plant gate prices for the year
ended December 31, 2007 for ammonia and UAN were greater
than plant gate prices for the comparable period of 2006 by 11%
and 30%, respectively. Our ammonia and UAN sales prices for
product shipped during the year ended December 31, 2006
generally followed volatile natural gas prices; however, it is
typical for the reported pricing in our fertilizer business to
lag the spot market prices for nitrogen fertilizer due to
forward price contracts. As a result, forward price contracts
entered into the late summer and fall of 2005 (during a period
of relatively high natural gas prices due to the impact of
hurricanes Rita and Katrina) comprised a significant portion of
the product shipped in the spring of 2006. However, as natural
gas prices moderated in the spring and summer of 2006, nitrogen
fertilizer prices declined and the spot and fill contracts
entered into and shipped during this lower natural gas prices
environment realized lower average plant gate price. Ammonia and
UAN sales prices for the year ended December 31, 2007
decoupled from natural gas prices and increased sharply driven
by increased demand for fertilizer due to the increased use of
corn for the production of ethanol and an overall increase in
prices for corn, wheat and soybeans, which are the primary row
112
crops in our region. This increase in demand for nitrogen
fertilizer has created an environment in which nitrogen
fertilizer prices have disconnected from their traditional
correlation to natural gas.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold exclusive
of depreciation and amortization is primarily comprised of
petroleum coke expense, hydrogen reimbursement and freight and
distribution expenses. Cost of product sold excluding
depreciation and amortization for the year ended
December 31, 2007 was $13.0 million compared to
$25.9 million for the year ended December 31, 2006.
The decrease of $12.9 million for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 was primarily the result of increased
hydrogen reimbursement due to the transfer of hydrogen to our
petroleum operations to facilitate sulfur recovery in the ultra
low sulfur diesel production unit and reduced freight expense
partially offset by an increase in petroleum coke costs. In
2007, pet coke costs increased as the nitrogen fertilizer
business purchased more pet coke from third parties than is
typical as a result of the flood, which reduced our
refinerys pet coke production.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
our Nitrogen fertilizer operations include costs associated with
the actual operations of our nitrogen plant, such as repairs and
maintenance, energy and utility costs, catalyst and chemical
costs, outside services, labor and environmental compliance
costs. Nitrogen direct operating expenses exclusive of
depreciation and amortization for the year ended
December 31, 2007 were $66.7 million as compared to
$63.7 million for the year ended December 31, 2006.
The increase of $3.0 million for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 was primarily the result of increases in
repairs and maintenance ($6.5 million), equipment rental
($0.6 million) environmental ($0.4 million), utilities
($0.3 million), and insurance ($0.3 million). These
increases in direct operating expenses were partially offset by
reductions in expenses associated with turnaround
($2.6 million), royalties and other expense
($1.1 million), reimbursed expense ($0.6 million),
catalyst ($0.3 million), chemicals ($0.3 million) and
slag disposal ($0.2 million).
Net Costs Associated with
Flood.
Nitrogen fertilizer net costs
associated with flood for the year ended December 31, 2007
approximated $2.4 million as compared to none for the year
ended December 31, 2006. Total gross costs recorded as a
result of the physical damage to the fertilizer plant for the
year ended December 31, 2007 were approximately
$5.7 million. Included in the gross costs associated with
the flood were certain costs that are excluded from the accounts
receivable from insurers of approximately $3.3 million at
December 31, 2007, for which we believe collection is
probable. The costs excluded from the accounts receivable from
insurers were approximately $0.8 million recorded for
depreciation for the temporarily idle facilities,
$0.1 million of uninsured losses inside of the
Companys deductibles and $1.5 million of uninsured
expenses.
Depreciation and Amortization.
Nitrogen
fertilizer depreciation and amortization decreased to
$16.8 million for the year ended December 31, 2007 as
compared to $17.1 million for the year ended
December 31, 2006. During the restoration period for the
nitrogen fertilizer operations due to the flood,
$0.8 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $0.8 reclassification, nitrogen fertilizer depreciation and
amortization would have increased by approximately
$0.5 million for the year ended December 31, 2007
compared to the year ended December 31, 2006.
Operating Income.
Nitrogen fertilizer
operating income was $46.6 million for the year ended
December 31, 2007 as compared to $36.8 million for the
year ended December 31, 2006. This increase of
$9.8 million for the year ended December 31, 2007 as
compared to the year ended December 31, 2006 was primarily
the result of an increase in plant gate prices
($34.4 million), partially offset by reductions in overall
sales volumes ($31.0). In addition, a $12.9 million
reduction in cost of product sold excluding depreciation and
amortization due to increased hydrogen reimbursement and reduced
freight expense partially offset by an increase in petroleum
coke costs contributed to the positive variance in operating
income during for the year ended December 31, 2007 compared
to the year ended December 31, 2006. Partially offsetting
the positive effects of plant gate prices and cost of
113
product sold excluding depreciation and amortization was an
increase in direct operating expenses associated with repairs
and maintenance ($6.5 million), equipment rental
($0.6 million) environmental ($0.4 million), utilities
($0.3 million), and insurance ($0.3 million). These
increases in direct operating expenses were partially offset by
reductions in expenses associated with turnaround
($2.6 million), royalties and other expense
($1.1 million), reimbursed expense ($0.6 million),
catalyst ($0.3 million), chemicals ($0.3 million) and
slag disposal ($0.2 million).
Year Ended
December 31, 2006 Compared to the 174 Days Ended
June 23, 2005 and the 233 Days Ended December 31,
2005 (Nitrogen Fertilizer Business).
Net Sales.
Nitrogen fertilizer net
sales were $162.5 million for the year ended
December 31, 2006 compared to $79.3 million for the
174 days ended June 23, 2005 and $93.7 million
for the 233 days ended December 31, 2005. The decrease
of $10.5 million from the year ended December 31, 2006
as compared to the combined periods for the year ended
December 31, 2005 was the result of both decreases in
selling prices ($1.6 million) and reductions in overall
sales volumes ($8.9 million) of the fertilizer products as
compared to the year ended December 31, 2005.
Net sales for the year ended December 31, 2006 included
$121.1 million from the sale of UAN, $42.1 million
from the sale of ammonia and $6.8 million from the sale of
hydrogen to CVR Energy. Net sales for the year ended
December 31, 2005 included $122.2 million from the
sale of UAN, $48.6 million from the sale of ammonia and
$2.7 million from the sale of hydrogen to CVR Energy.
In regard to product sales volumes for the year ended
December 31, 2006, the nitrogen fertilizer operations
experienced a decrease of 17% in ammonia sales unit volumes
(24,500 tons) and a decrease of 0.2% in UAN sales unit volumes
(988 tons). The decrease in ammonia sales volume was the result
of decreased production volumes during the year ended
December 31, 2006 relative to the comparable period of 2005
due to the scheduled turnaround at the nitrogen fertilizer plant
during July 2006 and the transfer of hydrogen to our petroleum
operations to facilitate sulfur recovery in the ultra low sulfur
diesel production unit.
On-stream factors (total number of hours operated divided by
total hours in the reporting period) for all units of the
nitrogen fertilizer operations (gasifier, ammonia plant and UAN
plant) were less in 2006 than in 2005 primarily due to the
scheduled turnaround in July 2006 and downtime in the ammonia
plant due to a crack in the converter. It is typical to
experience brief outages in complex manufacturing operations
such as the nitrogen fertilizer plant which result in less than
100% on-stream availability for one or more specific units.
Plant gate prices are prices FOB the delivery point less any
freight cost absorbed to deliver the product. We believe plant
gate price is meaningful because the nitrogen fertilizer
business sells products both FOB the plant gate (sold plant) and
FOB the customers designated delivery site (sold
delivered) and the percentage of sold plant versus sold
delivered can change month to month or year to year. The plant
gate price provides a measure that is consistently comparable
period to period. Plant gate prices for the year ended
December 31, 2006 for ammonia were greater than plant gate
prices for the comparable period of 2005 by 4%. In contrast to
ammonia, UAN prices decreased for the year ended
December 31, 2006 as compared to the year ended
December 31, 2005 by 6%. The positive price comparisons for
ammonia sales, given the dramatic decline in natural gas prices
during the comparable periods, were the result of prepay
contracts executed during the period of relatively high natural
gas prices that resulted from the impact of hurricanes Katrina
and Rita on an already tight natural gas market.
Cost of Product Sold Exclusive of Depreciation and
Amortization.
Cost of product sold exclusive
of depreciation and amortization is primarily comprised of pet
coke expense and freight and distribution expenses. Cost of
product sold excluding depreciation and amortization for the
year ended December 31, 2006 was $25.9 million
compared to $9.1 million for the 174 days ended
June 23, 2005 and $14.5 million for the 233 days
ended December 31, 2005. The increase of $2.3 million
for the
114
year ended December 31, 2006 as compared to the combined
periods for the year ended December 31, 2005 was primarily
the result of increases in freight expense.
Depreciation and Amortization.
Nitrogen
fertilizer depreciation and amortization increased to
$17.1 million for the year ended December 31, 2006 as
compared to $0.3 million for the 174 days ended
June 23, 2005 and $8.4 million for the 233 days
ended December 31, 2005. This increase of $8.4 million
for the year ended December 31, 2006 as compared to the
combined periods for the year ended December 31, 2005 was
primarily the result of the
step-up
in
property, plant and equipment for the Subsequent Acquisition.
See Factors Affecting Comparability.
Direct Operating Expenses Exclusive of Depreciation and
Amortization.
Direct operating expenses for
the nitrogen fertilizer operations include costs associated with
the actual operations of the nitrogen fertilizer plant, such as
repairs and maintenance, energy and utility costs, catalyst and
chemical costs, outside services, labor and environmental
compliance costs. Nitrogen direct operating expenses exclusive
of depreciation and amortization for the year ended
December 31, 2006 were $63.7 million as compared to
$28.3 million for the 174 days ended June 23,
2005 and $29.2 million for the 233 days ended
December 31, 2005. The increase of $6.2 million for
the year ended December 31, 2006 as compared to the
combined periods for the year ended December 31, 2005 was
primarily the result of increases in labor ($0.7 million),
repairs and maintenance ($0.5 million), turnaround expenses
($2.6 million), outside services ($0.6 million),
utilities ($2.3 million) and insurance ($0.5 million),
partially offset by reductions in expenses related to catalyst
($0.6 million) and environmental ($0.8 million).
Operating Income.
Nitrogen fertilizer
operating income was $36.8 million for the year ended
December 31, 2006 as compared to $35.3 million for the
174 days ended June 23, 2005 and $35.7 million
for the 233 days ended December 31, 2005. This
decrease of $34.2 million for the year ended
December 31, 2006 as compared to the combined periods for
the year ended December 31, 2005 was the result of reduced
sales volumes, lower plant gate prices for UAN and increased
direct operating expenses related to labor ($0.7 million),
repairs and maintenance ($0.5 million), turnaround expenses
($2.6 million), outside services ($0.6 million),
utilities ($2.3 million), insurance ($0.5 million) and
depreciation ($8.4 million), partially offset by reductions
in expenses related to catalyst ($0.6 million) and
environmental ($0.8 million) and higher ammonia prices.
Liquidity and
Capital Resources
Our primary sources of liquidity currently consist of cash
generated from our operating activities, existing cash balances,
our existing revolving credit facility and third party
guarantees of obligations under the Cash Flow Swap as well as
our convertible notes offering, if consummated, and the proceeds
of our proposed senior secured credit facility, if entered into.
Our ability to generate sufficient cash flows from our operating
activities will continue to be primarily dependent on producing
or purchasing, and selling, sufficient quantities of refined
products at margins sufficient to cover fixed and variable
expenses.
As of March 31, 2008 and June 16, 2008, we had cash,
cash equivalents and short-term investments of
$25.2 million and $71.4 million, respectively, and up
to $112.6 million available under our revolving credit
facility as of both dates. In the current crude oil price
environment, working capital is subject to substantial
variability from week-to-week and month-to-month. The payable to
swap counterparty included in the consolidated balance sheet at
March 31, 2008 was approximately $371.4 million, and
the current portion included an increase of $32.6 million
from December 31, 2007, resulting in an equal reduction in
our working capital for the same period.
On June 30, 2007, our refinery and the nitrogen fertilizer
plant were severely flooded and forced to conduct emergency
shutdowns and evacuate. See Flood and Crude Oil
Discharge. Our liquidity was significantly negatively
impacted as a result of the reduction in cash provided by
operations due to our temporary cessation of operations and the
additional expenditures associated with the flood
115
and crude oil discharge. In order to provide immediate and
future liquidity, on August 23, 2007 we deferred payments
which were due to J. Aron under the terms of the Cash Flow Swap.
The J. Aron deferred amounts of $123.7 million (plus
accrued interest of $5.8 million as of June 1,
2008) are due on August 31, 2008. See
Liquidity and Capital Resources
Payment Deferrals Related to the Cash Flow Swap for
additional information about the payment deferral. These
deferrals are supported by third-party guarantees. In addition,
we estimate that we will owe J. Aron approximately
$54 million on July 8, 2008 for crude oil we settled
with respect to the quarter ending June 30, 2008 based on
June 16, 2008 pricing.
Our liquidity was enhanced during the fourth quarter of 2007 by
the receipt of the net proceeds from our initial public
offering. We intend to use the net proceeds from the convertible
notes offering, if consummated, and the proposed senior secured
credit facility, if entered into, for general corporate
purposes, which may include using a portion of the proceeds to
pay amounts owed to J. Aron under the Cash Flow Swap and for
other future capital investments. If the convertible notes
offering is not consummated
and/or
the
proposed senior secured credit facility is not entered into, we
intend to fund our operations through cash generated from our
operating activities, existing cash balances, our existing
revolving credit facility and third party guarantees of
obligations under the Cash Flow Swap. We believe these capital
resources will be sufficient to satisfy the anticipated cash
requirements associated with our existing operations for at
least the next twelve months. However, our future capital
expenditures and other cash requirements could be higher than we
currently expect as a result of various factors. Additionally,
our ability to generate sufficient cash from our operating
activities depends on our future performance, which is subject
to general economic, political, financial, competitive and other
factors beyond our control.
Debt
Proposed
Secured Credit Facility
Concurrently with the closing of this offering, we anticipate
that Coffeyville Resources, LLC will enter into a new
$25.0 million senior secured term loan (the proposed
senior secured credit facility). We anticipate that the
proposed senior secured credit facility will be secured by the
same collateral that secures our existing Credit Facility and
will contain covenants substantially similar to the Credit
Facility described below. Although we have begun negotiations on
the new credit facility, we have not entered into any agreement
regarding the proposed senior secured credit facility, and as
such, there is no guarantee that we will be enter into a credit
facility on the terms described above or at all.
Credit
Facility
On December 28, 2006, our subsidiary, Coffeyville
Resources, LLC, entered into a credit facility (the Credit
Facility) which provided financing of up to
$1.075 billion. The Credit Facility consisted of
$775.0 million of tranche D term loans, a
$150.0 million revolving credit facility, and a funded
letter of credit facility of $150.0 million issued in
support of the Cash Flow Swap. On October 26, 2007, we
repaid $280.0 million of the tranche D term loans with
proceeds from our initial public offering. The Credit Facility
is guaranteed by all of our subsidiaries and is secured by
substantially all of their assets including the equity of our
subsidiaries on a first-lien priority basis.
The tranche D term loans outstanding are subject to
quarterly principal amortization payments of 0.25% of the
outstanding balance commencing on April 1, 2007 and
increasing to 23.5% of the outstanding principal balance on
April 1, 2013 and the next two quarters, with a final
payment of the aggregate outstanding balance on
December 28, 2013.
The revolving credit facility of $150.0 million provides
for direct cash borrowings for general corporate purposes and on
a short-term basis. Letters of credit issued under the revolving
credit facility are subject to a $75.0 million sub-limit.
The revolving loan commitment expires on December 28, 2012.
The borrower has an option to extend this maturity upon written
notice to the lenders; however, the revolving loan maturity
cannot be extended beyond the final maturity of the term loans,
which is
116
December 28, 2013. As of March 31, 2008, we had
available $112.6 million under the revolving credit
facility. As of June 16, 2008, we had available
$112.6 million under the revolving credit facility.
The $150.0 million funded letter of credit facility
provides credit support for our obligations under the Cash Flow
Swap. The funded letter of credit facility is fully cash
collateralized by the funding by the lenders of cash into a
credit linked deposit account. This account is held by the
funded letter of credit issuing bank. Contingent upon the
requirements of the Cash Flow Swap, the borrower has the ability
to reduce the funded letter of credit at any time upon written
notice to the lenders. The funded letter of credit facility
expires on December 28, 2010.
The Credit Facility incorporates the following pricing by
facility type:
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Tranche D term loans bear interest at either (a) the
greater of the prime rate and the federal funds effective rate
plus 0.5%, plus in either case 2.25%, or, at the borrowers
option, (b) LIBOR plus 3.25% (with step-downs to the prime
rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75%
or 2.50%, respectively, upon achievement of certain rating
conditions).
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Revolving loan borrowings bear interest at either (a) the
greater of the prime rate and the federal funds effective rate
plus 0.5%, plus in either case 2.25%, or, at the borrowers
option, (b) LIBOR plus 3.25% (with step-downs to the prime
rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75%
or 2.50%, respectively, upon achievement of certain rating
conditions).
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Letters of credit issued under the $75.0 million sub-limit
available under the revolving loan facility are subject to a fee
equal to the applicable margin on revolving LIBOR loans owing to
all revolving lenders and a fronting fee of 0.25% per annum
owing to the issuing lender.
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Funded letters of credit are subject to a fee equal to the
applicable margin on term LIBOR loans owed to all funded letter
of credit lenders and a fronting fee of 0.125% per annum owing
to the issuing lender. The borrower is also obligated to pay a
fee of 0.10% to the administrative agent on a quarterly basis
based on the average balance of funded letters of credit
outstanding during the calculation period, for the maintenance
of a credit-linked deposit account backstopping funded letters
of credit.
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In addition to the fees stated above, the Credit Facility
requires the borrower to pay 0.50% per annum in commitment fees
on the unused portion of the revolving loan facility.
The Credit Facility requires the borrower to prepay outstanding
loans, subject to certain exceptions, with:
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100% of the net asset sale proceeds received from specified
asset sales and net insurance/ condemnation proceeds, if the
borrower does not reinvest those proceeds in assets to be used
in its business or make other permitted investments within
12 months or if, within 12 months of receipt, the
borrower does not contract to reinvest those proceeds in assets
to be used in its business or make other permitted investments
within 18 months of receipt, each subject to certain
limitations;
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100% of the cash proceeds from the incurrence of specified debt
obligations; and
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75% of consolidated excess cash flow less 100% of
voluntary prepayments made during the fiscal year; provided that
with respect to any fiscal year commencing with fiscal 2008 this
percentage will be reduced to 50% if the total leverage ratio at
the end of such fiscal year is less than 1.50:1.00 or 25% if the
total leverage ratio as of the end of such fiscal year is less
than 1.00:1.00.
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Mandatory prepayments will be applied first to the term loan,
second to the swing line loans, third to the revolving loans,
fourth to outstanding reimbursement obligations with respect to
revolving letters of credit and funded letters of credit, and
fifth to cash collateralize revolving letters of credit and
117
funded letters of credit. Voluntary prepayments of loans under
the Credit Facility are permitted, in whole or in part, at the
borrowers option, without premium or penalty.
The Credit Facility contains customary covenants. These
agreements, among other things, restrict, subject to certain
exceptions, the ability of Coffeyville Resources, LLC and its
subsidiaries to incur additional indebtedness, create liens on
assets, make restricted junior payments, enter into agreements
that restrict subsidiary distributions, make investments, loans
or advances, engage in mergers, acquisitions or sales of assets,
dispose of subsidiary interests, enter into sale and leaseback
transactions, engage in certain transactions with affiliates and
stockholders, change the business conducted by the credit
parties, and enter into hedging agreements. The Credit Facility
provides that Coffeyville Resources, LLC may not enter into
commodity agreements if, after giving effect thereto, the
exposure under all such commodity agreements exceeds 75% of
Actual Production (the borrowers estimated future
production of refined products based on the actual production
for the three prior months) or for a term of longer than six
years from December 28, 2006. In addition, the borrower may
not enter into material amendments related to any material
rights under the Cash Flow Swap or the Partnerships
partnership agreement without the prior written approval of the
lenders. These limitations are subject to critical exceptions
and exclusions and are not designed to protect investors in our
common stock.
The Credit Facility also requires the borrower to maintain
certain financial ratios as follows:
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Minimum
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Interest
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Maximum
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Coverage
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Leverage
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Fiscal Quarter Ending
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Ratio
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Ratio
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June 30, 2008
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3.25:1.00
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3.00:1.00
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September 30, 2008
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3.25:1.00
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2.75:1.00
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December 31, 2008
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3.25:1.00
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2.50:1.00
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March 31, 2009 and thereafter
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3.75:1.00
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2.25:1.00 to
December 31, 2009
2.00:1.00 thereafter
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The computation of these ratios is governed by the specific
terms of the Credit Facility and may not be comparable to other
similarly titled measures computed for other purposes or by
other companies. The minimum interest coverage ratio is the
ratio of consolidated adjusted EBITDA to consolidated cash
interest expense over a four quarter period. The maximum
leverage ratio is the ratio of consolidated total debt to
consolidated adjusted EBITDA over a four quarter period. The
computation of these ratios requires a calculation of
consolidated adjusted EBITDA. In general, under the terms of our
Credit Facility, consolidated adjusted EBITDA is calculated by
adding consolidated net income, consolidated interest expense,
income taxes, depreciation and amortization, other non- cash
expenses, any fees and expenses related to permitted
acquisitions, any non-recurring expenses incurred in connection
with the issuance of debt or equity, management fees, any
unusual or non-recurring charges up to 7.5% of consolidated
adjusted EBITDA, any net after-tax loss from disposed or
discontinued operations, any incremental property taxes related
to abatement non-renewal, any losses attributable to minority
equity interests and major scheduled turnaround expenses. As of
the date of this prospectus, we were in compliance with our
covenants under the Credit Facility.
118
We present consolidated adjusted EBITDA because it is a material
component of material covenants within our current Credit
Facility and significantly impacts our liquidity and ability to
borrow under our revolving line of credit. However, consolidated
adjusted EBITDA is not a defined term under GAAP and should not
be considered as an alternative to operating income or net
income as a measure of operating results or as an alternative to
cash flows as a measure of liquidity. Consolidated adjusted
EBITDA is calculated under the Credit Facility as follows:
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Immediate
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Predecessor and
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Successor
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Combined
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(Non-GAAP)
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Successor
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Year Ended December 31,
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Three Months Ended March 31,
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Consolidated Financial
Results
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2005
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2006
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2007
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2007
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2008
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(unaudited)
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(in millions)
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(unaudited in millions)
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Net income (loss)
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$
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(66.8
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)
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$
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191.6
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$
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(67.6
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$
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(154.4
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)
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$
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22.2
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Plus:
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Depreciation and amortization
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25.1
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51.0
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68.4
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14.2
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19.6
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Interest expense
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32.8
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43.9
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61.1
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11.9
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11.3
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Income tax expense (benefit)
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(26.9
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)
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119.8
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(88.5
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)
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(47.3
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)
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6.9
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Loss on extinguishment of debt
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8.1
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23.4
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1.3
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Inventory fair market value adjustment
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16.6
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Funded letters of credit expenses and interest rate swap not
included in interest expense
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2.3
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1.8
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0.9
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Major scheduled turnaround expense
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6.6
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76.4
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66.0
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Loss on termination of Swap
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25.0
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Unrealized (gain) or loss on derivatives
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229.8
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(128.5
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)
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113.5
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126.9
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18.9
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Non-cash compensation expense for equity awards
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1.8
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16.9
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43.5
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3.7
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(0.4
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(Gain) or loss on disposition of fixed assets
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1.2
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1.3
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Expenses related to acquisition
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3.5
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Minority interest in subsidiaries
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(0.2
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(0.7
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Management fees
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2.3
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2.3
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11.7
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0.5
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Consolidated adjusted EBITDA
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$
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253.6
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$
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328.2
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$
|
222.7
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$
|
20.8
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$
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79.4
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In addition to the financial covenants summarized in the table
above, the Credit Facility restricts the capital expenditures of
Coffeyville Resources, LLC to $125.0 million in 2008,
$125.0 million in 2009, $80.0 million in 2010, and
$50.0 million in 2011 and thereafter. The capital
expenditures covenant includes a mechanism for carrying over the
excess of any previous years capital expenditure limit.
The capital expenditures limitation will not apply for any
fiscal year commencing with fiscal 2009 if the borrower obtains
a total leverage ratio of less than or equal to 1.25:1.00 for
any quarter commencing with the quarter ending December 31,
2008. We believe the limitations on our capital expenditures
imposed by the Credit Facility should allow us to meet our
current capital expenditure needs. However, if future events
require us or make it beneficial for us to make capital
expenditures beyond those currently planned, we would need to
obtain consent from the lenders under our Credit Facility.
119
The Credit Facility also contains customary events of default.
The events of default include the failure to pay interest and
principal when due, including fees and any other amounts owed
under the Credit Facility, a breach of certain covenants under
the Credit Facility, a breach of any representation or warranty
contained in the Credit Facility, any default under any of the
documents entered into in connection with the Credit Facility,
the failure to pay principal or interest or any other amount
payable under other debt arrangements in an aggregate amount of
at least $20.0 million, a breach or default with respect to
material terms under other debt arrangements in an aggregate
amount of at least $20.0 million which results in the debt
becoming payable or declared due and payable before its stated
maturity, a breach or default under the Cash Flow Swap that
would permit the holder or holders to terminate the Cash Flow
Swap, events of bankruptcy, judgments and attachments exceeding
$20.0 million, events relating to employee benefit plans
resulting in liability in excess of $20.0 million, a change
in control, the guarantees, collateral documents or the Credit
Facility failing to be in full force and effect or being
declared null and void, any guarantor repudiating its
obligations, the failure of the collateral agent under the
Credit Facility to have a lien on any material portion of the
collateral, and any party under the Credit Facility (other than
the agent or lenders under the Credit Facility) contesting the
validity or enforceability of the Credit Facility.
Under the terms of our Credit Facility, our initial public
offering was deemed a Qualified IPO because the
offering generated more than $250.0 million of gross
proceeds and we used the proceeds of the offering to repay at
least $275.0 million of term loans under the Credit
Facility. As a result of our Qualified IPO, the interest margin
on LIBOR loans may in the future decrease from 3.25% to 2.75%
(if we have credit ratings of B2/B) or 2.50% (if we have
credit ratings of B1/B+). Interest on base rate loans will
similarly be adjusted. In addition, as a result of our Qualified
IPO, (1) we will be allowed to borrow an additional
$225.0 million under the Credit Facility after
June 30, 2008 to finance capital enhancement projects if we
are in pro forma compliance with the financial covenants in the
Credit Facility and the rating agencies confirm our ratings,
(2) we will be allowed to pay an additional
$35.0 million of dividends each year, if our corporate
family ratings are at least B2 from Moodys and B from
S&P, (3) we will not be subject to any capital
expenditures limitations commencing with fiscal 2009 if our
total leverage ratio is less than or equal to 1.25:1 for any
quarter commencing with the quarter ending December 31,
2008, and (4) at any time after March 31, 2008 we will
be allowed to reduce the Cash Flow Swap to not less than
35,000 barrels a day for fiscal 2008 and terminate the Cash
Flow Swap for any year commencing with fiscal 2009, so long as
our total leverage ratio is less than or equal to 1.25:1 and we
have a corporate family rating of at least B2 from Moodys
and B from S&P.
The Credit Facility is subject to an intercreditor agreement
among the lenders and the Cash Flow Swap provider, which deal
with, among other things, priority of liens, payments and
proceeds of sale of collateral.
At March 31, 2008 and December 31, 2007, funded
long-term debt, including current maturities, totaled
$488.0 million and $489.2 million, respectively, of
tranche D term loans. Other commitments at March 31,
2008 and December 31, 2007 included a $150.0 million
funded letter of credit facility and a $150.0 million
revolving credit facility. As of March 31, 2008, the
commitment outstanding on the revolving credit facility was
$37.4 million, including $5.8 million in letters of
credit in support of certain environmental obligations and
$31.6 million in letters of credit to secure transportation
services for crude oil. As of December 31, 2007, the
commitment outstanding on the revolving credit facility was
$39.4 million, including $5.8 million in letters of
credit in support of certain environmental obligations,
$3.0 million in support of surety bonds in place to support
state and federal excise tax for refined fuels, and
$30.6 million in letters of credit to secure transportation
services for crude oil.
August 2007
Credit Facilities
The 2007 flood and crude oil discharge had a significant
negative effect on our liquidity in July/August 2007. We did not
generate any material revenue while our facilities were shut
down due to the flood, but we incurred and continue to incur
significant flood repair and cleanup costs, as well as
120
incremental legal, public relations and crisis management costs.
We also had significant contractual obligations to purchase
gathered crude oil. We also owed J. Aron approximately
$123.7 million under the Cash Flow Swap, which we deferred
to January 31, 2008 (see Payment
Deferrals Related to Cash Flow Swap below). In addition,
although we believe that we will recover substantial sums under
our insurance policies, we are not sure of the ultimate amount
or timing of such recovery.
As a result of these factors, in August 2007 our subsidiaries
entered into three new credit facilities.
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$25.0 Million Secured Facility.
Coffeyville Resources, LLC entered into a new $25.0 million
senior secured term loan (the $25.0 million secured
facility). The facility was secured by the same collateral
that secures our existing Credit Facility. Interest was payable
in cash, at our option, at the base rate plus 1.00% or at the
reserve adjusted eurodollar rate plus 2.00%.
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$25.0 Million Unsecured Facility.
Coffeyville Resources, LLC entered into a new $25.0 million
senior unsecured term loan (the $25.0 million
unsecured facility). Interest was payable in cash, at our
option, at the base rate plus 1.00% or at the reserve adjusted
eurodollar rate plus 2.00%.
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$75.0 Million Unsecured Facility.
Coffeyville Refining & Marketing
Holdings, Inc. entered into a new $75.0 million senior
unsecured term loan (the $75.0 million unsecured
facility). Drawings could be made from time to time in
amounts of at least $5.0 million. Interest accrued, at our
option, at the base rate plus 1.50% or at the reserve adjusted
eurodollar rate plus 2.50%. Interest was paid by adding such
interest to the principal amount of loans outstanding. In
addition, a commitment fee equal to 1.00% accrued and was paid
by adding such fees to the principal amount of loans
outstanding. No amounts were drawn under this facility.
|
All indebtedness outstanding under the $25.0 million
secured facility and the $25.0 million unsecured facility
was repaid in October 2007 with the proceeds of our initial
public offering, and all three facilities were terminated at
that time.
Payment
Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, Coffeyville Resources, LLC
entered into several deferral agreements with J. Aron with
respect to the Cash Flow Swap. These deferral agreements
deferred to January 31, 2008 the payment of approximately
$123.7 million (plus accrued interest) which we owed to J.
Aron. J. Aron has agreed to further defer these payments to
August 31, 2008. We are required to use 37.5% of our
consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferred amounts, but as of
March 31, 2008 we were not required to prepay any portion
of the deferred amount.
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On June 26, 2007, Coffeyville Resources, LLC and J.
Aron & Company entered into a letter agreement in
which J. Aron deferred to August 7, 2007 a
$45.0 million payment which we owed to J. Aron under the
Cash Flow Swap for the period ending June 30, 2007. We
agreed to pay interest on the deferred amount at the rate of
LIBOR plus 3.25%.
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On July 11, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred to
July 25, 2007 a separate $43.7 million payment which
we owed to J. Aron under the Cash Flow Swap for the period
ending June 30, 2007. J. Aron deferred the
$43.7 million payment on the conditions that (a) each
of GS Capital Partners V Fund, L.P. and Kelso Investment
Associates VII, L.P. agreed to guarantee one-half of the payment
and (b) interest accrued on the $43.7 million from
July 9, 2007 to the date of payment at the rate of LIBOR
plus 1.50%.
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On July 26, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred to
September 7, 2007 both the $45.0 million payment due
August 7, 2007 (and accrued interest) and the
$43.7 million payment due July 25, 2007 (and accrued
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interest). J. Aron deferred these payments on the conditions
that (a) each of GS Capital Partners V Fund, L.P. and Kelso
Investment Associates VII, L.P. agreed to guarantee one-half of
the payments and (b) interest accrued on the amounts from
July 26, 2007 to the date of payment at the rate of LIBOR
plus 1.50%.
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On August 23, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred to
January 31, 2008 the $45.0 million payment due
September 7, 2007 (and accrued interest), the
$43.7 million payment due September 7, 2007 (and
accrued interest) and the $35.0 million payment which we
owed to J. Aron under the Cash Flow Swap to settle hedged volume
through August 15, 2007. J. Aron deferred these payments
(totaling $123.7 million, plus accrued interest) on the
conditions that (a) each of GS Capital Partners V Fund,
L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payments and (b) interest accrued
on the amounts to the date of payment at the rate of LIBOR plus
1.50%.
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Nitrogen
Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time
to time, seek to raise capital through a public or private
offering of limited partner interests in the Partnership. Any
decision to pursue such a transaction would be made in the
discretion of the managing general partner, not us, and any
proceeds raised in a primary offering would be for the benefit
of the Partnership, not us (although in some cases, depending on
the structure of the transaction, the Partnership might remit
proceeds to us). If the managing general partner elects to
pursue a public or private offering of limited partner interests
in the Partnership, we expect that any such transaction would
require amendments to our Credit Facility, as well as to the
Cash Flow Swap, in order to remove the Partnership and its
subsidiaries as obligors under such instruments. Any such
amendments could result in significant changes to our Credit
Facilitys pricing, mandatory repayment provisions,
covenants and other terms and could result in increased interest
costs and require payment by us of additional fees. We have
agreed to use our commercially reasonable efforts to obtain such
amendments if the managing general partner elects to cause the
Partnership to pursue a public or private offering and gives us
at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any
such amendment on terms acceptable to us or at all. If we are
not able to amend our Credit Facility on terms satisfactory to
us, we may need to refinance it with other facilities. We will
not be considered to have used our commercially reasonable
efforts to obtain such amendments if we do not effect the
requested modifications due to (i) payment of fees to the
lenders or the swap counterparty, (ii) the costs of this
type of amendment, (iii) an increase in applicable margins
or spreads or (iv) changes to the terms required by the
lenders including covenants, events of default and repayment and
prepayment provisions; provided that (i), (ii), (iii) and
(iv) in the aggregate are not likely to have a material
adverse effect on us. In order to effect the requested
amendments, we may require that (1) the Partnerships
initial public or private offering generate at least
$140.0 million in net proceeds to us and (2) the
Partnership raise an amount of cash (from the issuance of equity
or incurrence of indebtedness) equal to $75.0 million minus
the amount of capital expenditures for which it will reimburse
us from the proceeds of its initial public or private offering
and to distribute that cash to us prior to, or concurrently
with, the closing of its initial public or private offering. If
the managing general partner sells interests to third party
investors, we expect that the Partnership may at such time seek
to enter into its own credit facility.
The Partnership filed a registration statement in
February 2008 for an initial public offering of its common
units. On June 13, 2008, we announced that the managing
general partner of the Partnership has decided to postpone
indefinitely the Partnerships initial public offering due
to current market conditions for master limited partnerships. We
believe maintaining the fertilizer business within the Company
provides greater value for CVR Energy shareholders than would be
the case if the Partnership became a publicly-traded partnership
at this time. The Partnership subsequently
122
requested that the registration statement be withdrawn. The
Partnership may elect to move forward with a public or private
offering in the future. Any future public or private offering by
the Partnership would be made solely at the discretion of the
Partnerships managing general partner, subject to our
specified joint management rights, and would be subject to
market conditions and negotiation of terms acceptable to the
Partnerships managing general partner. In connection with
the Partnerships initial public or private offering, if
any, the Partnership may require us to include a sale of a
portion of our interests in the Partnership. If the Partnership
becomes a public company, we may consider a secondary offering
of interests which we own (either in connection with a public
offering by the Partnership, but subject to priority rights in
favor of the Partnership, or following completion of the
Partnerships initial public offering, if any) or in a
private placement. We cannot assure you that any such
transaction will be consummated. Neither the consent of the
managing general partner nor the consent of the Partnership is
required for any sale of our interests in the Partnership, other
than customary blackout periods relating to offerings by the
Partnership. Any proceeds raised would be for our benefit. The
Partnership has granted us registration rights which will
require the Partnership to register our interests with the SEC
at our request from time to time (following any public offering
by the Partnership), subject to various limitations and
requirements. We cannot assure you that any such transaction
will be consummated.
Capital
Spending
We divide our capital spending needs into two categories:
non-discretionary, which is either capitalized or expensed, and
discretionary, which is capitalized. Non-discretionary capital
spending, such as for planned turnarounds and other maintenance,
is required to maintain safe and reliable operations or to
comply with environmental, health and safety regulations. The
total non-discretionary capital spending needs for our refinery
business and the nitrogen fertilizer business, including major
scheduled turnaround expenses, were approximately
$170 million in 2006 and $218 million in 2007 and we
estimate that the total non-discretionary capital spending needs
of our refinery business and the nitrogen fertilizer business
will be approximately $279 million in the aggregate over
the three-year period beginning 2008. These estimates include,
among other items, the capital costs necessary to comply with
environmental regulations, including Tier II gasoline
standards and on-road diesel regulations. As described above,
our credit facility limits the amount we can spend on capital
expenditures.
Compliance with the Tier II gasoline and on-road diesel
standards required us to spend approximately $133 million
during 2006 and approximately $103 million during 2007, and
we estimate that compliance will require us to spend
approximately $68 million in the aggregate between 2008 and
2010. These amounts are reflected in the table below under
Environmental and safety capital needs. See
Business Environmental Matters
Fuel Regulations Tier II, Low Sulfur
Fuels.
The following table sets forth our estimate of non-discretionary
spending for our refinery business and the nitrogen fertilizer
business for the years presented as of March 31, 2008
(other than 2006 and 2007 which reflect actual spending).
Capital spending for the nitrogen fertilizer business has been
and will be determined by the managing general partner of the
Partnership. The data contained in the table below represents
our current plans, but these plans may change as a result of
unforeseen
123
circumstances and we may revise these estimates from time to
time or not spend the amounts in the manner allocated below.
Petroleum
Business
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|
|
|
|
|
|
|
|
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|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
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|
|
2012
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Cumulative
|
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|
|
|
|
|
|
|
|
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(in millions)
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|
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|
|
|
|
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Environmental and safety capital needs
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$
|
144.6
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$
|
121.8
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$
|
46.0
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|
$
|
53.9
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|
$
|
23.5
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|
$
|
2.6
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$
|
2.1
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$
|
394.5
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Sustaining capital needs
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11.8
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14.9
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22.0
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29.8
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22.3
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22.0
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22.0
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144.8
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|
|
156.4
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|
136.7
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68.0
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83.7
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|
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45.8
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24.6
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|
24.1
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|
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539.3
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Major scheduled turnaround expenses
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4.0
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76.4
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50.0
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|
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130.4
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Total estimated non-discretionary spending
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$
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160.4
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$
|
213.1
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$
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68.0
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$
|
83.7
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$
|
95.8
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$
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24.6
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$
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24.1
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$
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669.7
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Nitrogen
Fertilizer Business
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2006
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2007
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2008
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2009
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2010
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2011
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2012
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Cumulative
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(in millions)
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Environmental and safety capital needs
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$
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0.1
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$
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0.5
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$
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2.2
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$
|
4.5
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|
$
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2.6
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2.7
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3.8
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$
|
16.4
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Sustaining capital needs
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6.6
|
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|
|
3.9
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9.7
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3.1
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4.5
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4.8
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4.3
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36.9
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6.7
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4.4
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11.9
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7.6
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7.1
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7.5
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|
8.1
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|
|
53.3
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Major scheduled turnaround expenses
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|
2.6
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|
|
|
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2.8
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|
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2.6
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|
|
|
|
|
2.8
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|
10.8
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|
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|
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|
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Total estimated non-discretionary spending
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$
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9.3
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|
$
|
4.4
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$
|
14.7
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|
|
$
|
7.6
|
|
|
$
|
9.7
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|
|
$
|
7.5
|
|
|
$
|
10.9
|
|
|
$
|
64.1
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Combined
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|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
2006
|
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|
2007
|
|
|
2008
|
|
|
2009
|
|
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2010
|
|
|
2011
|
|
|
2012
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Cumulative
|
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|
|
|
|
|
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(in millions)
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|
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|
|
|
|
|
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Environmental and safety capital needs
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$
|
144.7
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|
|
$
|
122.3
|
|
|
$
|
48.2
|
|
|
$
|
58.4
|
|
|
$
|
26.1
|
|
|
|
5.3
|
|
|
|
5.9
|
|
|
$
|
410.9
|
|
Sustaining capital needs
|
|
|
18.4
|
|
|
|
18.8
|
|
|
|
31.7
|
|
|
|
32.9
|
|
|
|
26.8
|
|
|
|
26.8
|
|
|
|
26.3
|
|
|
|
181.7
|
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163.1
|
|
|
|
141.1
|
|
|
|
79.9
|
|
|
|
91.3
|
|
|
|
52.9
|
|
|
|
32.1
|
|
|
|
32.2
|
|
|
|
592.6
|
|
Major scheduled turnaround expenses
|
|
|
6.6
|
|
|
|
76.4
|
|
|
|
2.8
|
|
|
|
|
|
|
|
52.6
|
|
|
|
|
|
|
|
2.8
|
|
|
|
141.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total estimated non-discretionary spending
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|
$
|
169.7
|
|
|
$
|
217.5
|
|
|
$
|
82.7
|
|
|
$
|
91.3
|
|
|
$
|
105.5
|
|
|
$
|
32.1
|
|
|
$
|
35.0
|
|
|
$
|
733.8
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We undertake discretionary capital spending based on the
expected return on incremental capital employed. Discretionary
capital projects generally involve an expansion of existing
capacity, improvement in product yields,
and/or
a
reduction in direct operating expenses. As of December 31,
2007, we had committed approximately $14 million towards
discretionary capital spending in 2008. Other than the nitrogen
fertilizer plant expansion project referred to below, we
anticipate that our discretionary capital spending will average
approximately $35 million per year between 2008 and 2012.
The Partnership is currently moving forward with an
approximately $120 million fertilizer plant expansion, of
which approximately $11 million was incurred as of
March 31, 2008. We estimate this expansion will increase
the nitrogen fertilizer plants capacity to upgrade ammonia
into premium priced UAN by approximately 50%. Management
currently expects to complete this expansion in July 2010. This
project is also expected to improve the cost structure of the
nitrogen fertilizer business by eliminating the need for rail
shipments of ammonia, thereby avoiding anticipated cost
increases in such transport.
124
Cash
Flows
The following table sets forth our cash flows for the periods
indicated below:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
233 Days
|
|
|
Year
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Three Months
|
|
|
|
June 23,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Ended March 31,
|
|
|
|
2005
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Net cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
12.7
|
|
|
$
|
82.5
|
|
|
$
|
186.6
|
|
|
$
|
145.9
|
|
|
$
|
44.1
|
|
|
$
|
24.2
|
|
Investing activities
|
|
|
(12.3
|
)
|
|
|
(730.3
|
)
|
|
|
(240.2
|
)
|
|
|
(268.6
|
)
|
|
|
(107.3
|
)
|
|
|
(26.2
|
)
|
Financing activities
|
|
|
(52.4
|
)
|
|
|
712.5
|
|
|
|
30.8
|
|
|
|
111.3
|
|
|
|
28.9
|
|
|
|
(3.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(52.0
|
)
|
|
$
|
64.7
|
|
|
$
|
(22.8
|
)
|
|
$
|
(11.4
|
)
|
|
$
|
(34.3
|
)
|
|
$
|
(5.4
|
)
|
In addition, we are currently entitled to all cash distributed
by the Partnership. However, the amount of cash flows from the
Partnership that we will receive in the future may be limited by
a number of factors. The Partnership may enter into its own
credit facility or other contracts that limit its ability to
make distributions to us. Additionally, in the future the
managing general partner of the Partnership will receive a
greater allocation of distributions as more cash becomes
available for distribution, and consequently we will receive a
smaller percentage of quarterly distributions over time. Our
rights to distributions will also be adversely affected if the
Partnership consummates a public or private equity offering in
the future. See Risk Factors Risks Related to
the Limited Partnership Structure Through Which We Hold Our
Interest in the Nitrogen Fertilizer Business Our
rights to receive distributions from the Partnership may be
limited over time and Risk Factors Risks
Related to the Nitrogen Fertilizer Business The
nitrogen fertilizer business may not have sufficient cash to
enable it to make quarterly distributions to us following the
payment of expenses and fees and the establishment of cash
reserves.
Cash Flows
Provided by Operating Activities
Comparison of
the Three Months Ended March 31, 2008 and the Three Months
Ended March 31, 2007
Net cash flows from operating activities for the three months
ended March 31, 2008 was $24.2 million. The positive
cash flow from operating activities generated over this period
was primarily driven by favorable changes in other working
capital and other assets and liabilities, partially offset by
unfavorable changes in trading working capital over the period.
For purposes of this cash flow discussion, we define trade
working capital as accounts receivable, inventory and accounts
payable. Other working capital is defined as all other current
assets and liabilities except trade working capital. Net income
for the period was not indicative of the operating margins for
the period. This is the result of the accounting treatment of
our derivatives in general and, more specifically, the Cash Flow
Swap. We have determined that the Cash Flow Swap does not
qualify as a hedge for hedge accounting purposes under
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities.
Therefore, the net loss for the
three months ended March 31, 2008 included both the
realized losses and the unrealized losses on the Cash Flow Swap.
Since the Cash Flow Swap had a significant term remaining as of
March 31, 2008 (approximately two years and three months)
and the NYMEX crack spread that is the basis for the underlying
swaps had increased, the unrealized losses on the Cash
125
Flow Swap significantly decreased our net income over this
period. The impact of these unrealized losses on the Cash Flow
Swap is apparent in the $20.8 million increase in the
payable to swap counterparty. Other sources of cash in other
working capital included $16.6 million of deferred revenue
related to prepaid fertilizer shipments and a $5.2 increase in
accrued income taxes. Trade working capital for the three months
ended March 31, 2008 resulted in a use of cash of
$67.5 million. For the three months ended March 31,
2008, accounts receivable increased $30.7 million,
inventory increased by $31.6 and accounts payable decreased by
$5.2 million.
Net cash flows provided by operating activities for the three
months ended March 31, 2007 was $44.1 million. The
positive cash flow from operating activities during this period
was primarily the result of changes in other assets and
liabilities offset by unfavorable changes in trade working
capital and other working capital. Net income for the period was
not indicative of the operating margins for the period. This was
the result of the accounting treatment of our derivatives in
general and, more specifically, the Cash Flow Swap. We have
determined that the Cash Flow Swap does not qualify as a hedge
for hedge accounting purposes under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities.
Therefore, the net loss for the three months ended
March 31, 2007 included both the realized losses and the
unrealized losses on the Cash Flow Swap. Since the Cash Flow
Swap had a significant term remaining as of March 31, 2007
(approximately three years and three months years) and the NYMEX
crack spread that is the basis for the underlying swaps had
increased during the period, the unrealized losses on the Cash
Flow Swap significantly decreased our net income over this
period. The impact of these unrealized losses on the Cash Flow
Swap is apparent in the $129.3 million increase in the
payable to swap counterparty. Adding to our operating cash flow
for the three months ended March 31, 2007 was a
$68.0 million source of cash related to a decrease in trade
working capital. For the three months ended March 31, 2007,
accounts receivable decreased $44.6 million while inventory
increased $23.0 million and accounts payable increased
$46.4 million. The change in trade working capital was
primarily driven by the impact of the refinery turnaround that
began in February 2007. The primary use of cash during the
period was $41.3 million for deferred income taxes
primarily the result of the unrealized loss on the Cash Flow
Swap.
Comparison of
the Year Ended December 31, 2007, the Year Ended
December 31, 2006, the 174 Days Ended June 23,
2005 and the 233 Days Ended December 31,
2005.
Net cash flows from operating activities for the year ended
December 31, 2007 was $145.9 million. The positive
cash flow from operating activities generated over this period
was primarily driven by favorable changes in other working
capital partially offset by unfavorable changes in trade working
capital and other assets and liabilities over the period. For
purposes of this cash flow discussion, we define trade working
capital as accounts receivable, inventory and accounts payable.
Other working capital is defined as all other current assets and
liabilities except trade working capital. Net income for the
period was not indicative of the operating margins for the
period. This is the result of the accounting treatment of our
derivatives in general and more specifically, the Cash Flow
Swap. We have determined that the Cash Flow Swap does not
qualify as a hedge for hedge accounting purposes under
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities.
Therefore, the net loss for the year
ended December 31, 2007 included both the realized losses
and the unrealized losses on the Cash Flow Swap. Since the Cash
Flow Swap had a significant term remaining as of
December 31, 2007 (approximately two years and six months)
and the NYMEX crack spread that is the basis for the underlying
swaps had increased, the unrealized losses on the Cash Flow Swap
significantly decreased our Net Income over this period. The
impact of these unrealized losses on the Cash Flow Swap is
apparent in the $240.9 million increase in the payable to
swap counterparty. Other sources of cash from other working
capital included $4.8 million from prepaid expenses and
other current assets, $27.0 million from other current
liabilities and $20.0 million in insurance proceeds.
Reducing our operating cash flow for the year ended
December 31, 2007 was $42.9 million use of cash
related to changes in trade working capital. For the year ended
December 31, 2007, accounts receivable increased
$17.0 million and inventory increased by $85.0 million
resulting in a net use of cash of $102.0 million. These
uses of cash due to changes in trade working
126
capital were partially offset by an increase in accounts
payable, or a source of cash, of $59.1 million. Other
primary uses of cash during the period include a
$105.3 million increase in our insurance receivable related
to the flood and a $57.7 million use of cash related to
deferred income taxes primarily the result of the unrealized
loss on the Cash Flow Swap.
Net cash flows from operating activities for the year ended
December 31, 2006 was $186.6 million. The positive
cash flow from operating activities generated over this period
was primarily driven by our strong operating environment and
favorable changes in other assets and liabilities, partially
offset by unfavorable changes in trade working capital and other
working capital over the period. Net income for the period was
not indicative of the operating margins for the period. This is
the result of the accounting treatment of our derivatives in
general and more specifically, the Cash Flow Swap. We have
determined that the Cash Flow Swap does not qualify as a hedge
for hedge accounting purposes under SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities
. Therefore, the net income for the year ended
December 31, 2006 included both the realized losses and the
unrealized gains on the Cash Flow Swap. Since the Cash Flow Swap
had a significant term remaining as of December 31, 2006
(approximately three years and six months) and the NYMEX crack
spread that is the basis for the underlying swaps had declined,
the unrealized gains on the Cash Flow Swap significantly
increased our net income over this period. The impact of these
unrealized gains on the Cash Flow Swap is apparent in the
$147.0 million decrease in the payable to swap
counterparty. Reducing our operating cash flow for the year
ended December 31, 2006 was a $0.3 million use of cash
related to an increase in trade working capital. For the year
ended December 31, 2006, accounts receivable decreased
approximately $1.9 million while inventory increased
$7.2 million and accounts payable increased
$5.0 million. Other primary uses of cash during the period
include a $5.4 million increase in prepaid expenses and
other current assets and a $37.0 million reduction in
accrued income taxes. Offsetting these uses of cash was an
$86.8 million increase in deferred income taxes primarily
the result of the unrealized gain on the Cash Flow Swap and a
$4.6 million increase in other current liabilities.
Analysis of cash flows from operating activities for the year
ended December 31, 2005 was impacted by the Subsequent
Acquisition. See Factors Affecting
Comparability. For instance, completion of the Subsequent
Acquisition by Successor required a mark up of purchased
inventory to fair market value at the closing of the transaction
on June 24, 2005. This had the effect of reducing overall
cash flow for Successor as it capitalized that portion of the
purchase price of the assets into cost of product sold.
Therefore, the discussion of cash flows from operations has been
broken down into the 174 days ended June 23, 2005 and
the 233 days ended December 31, 2005.
Net cash flows from operating activities for the 174 days
ended June 23, 2005 was $12.7 million. The positive
cash flow generated over this period was primarily driven by
income of $52.4 million, offset by a $54.3 million
increase in trade working capital. During this period, accounts
receivable and inventory increased $11.3 million and
$59.0 million, respectively. These uses of cash were
primarily the result of our expansion into the rack marketing
business, which offered increased accounts receivable credit
terms relative to bulk refined product sales, an increase in
product sales prices and an increase in overall inventory levels.
Net cash flows provided by operating activities for the
233 days ended December 31, 2005 was
$82.5 million. The positive cash flow from operating
activities generated over this period was primarily the result
of strong operating earnings during the period partially offset
by the expensing of a $25.0 million option entered into by
Successor for the purpose of hedging certain levels of refined
product margins and the accounting treatment of our derivatives
in general and more specifically, the Cash Flow Swap. At the
closing of the Subsequent Acquisition, we determined that this
option was not economical and we allowed the option to expire
worthless and thus resulted in the expensing of the associated
premium. See Quantitative and Qualitative
Disclosures About Market Risk Commodity Price
Risk and Results of
Operations Consolidated Results of
Operations Year Ended December 31, 2006
Compared to the 174 Days Ended June 23, 2005 and the 233
Days Ended December 31, 2005 (Consolidated). We have
determined that the Cash Flow Swap does not
127
qualify as a hedge for hedge accounting purposes under
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities.
Therefore, the net income for the
year ended December 31, 2005 included the unrealized losses
on the Cash Flow Swap. Since the Cash Flow Swap became effective
July 1, 2005 and had an original term of approximately five
years and the NYMEX crack spread that is the basis for the
underlying swaps had improved since the trade date of the Cash
Flow Swap on June 16, 2005, the unrealized losses on the
Cash Flow Swap significantly reduced our net income over this
period. The impact of these unrealized losses on all
derivatives, including the Cash Flow Swap, is apparent in the
$256.7 million increase in the payable to swap
counterparty. Additionally and as a result of the closing of the
Subsequent Acquisition, Successor marked up the value of
purchased inventory to fair market value at the closing of the
transaction on June 24, 2005. This had the effect of
reducing overall cash flow for Successor as it capitalized that
portion of the purchase price of the assets into cost of product
sold. The total impact of this for the 233 days ended
December 31, 2005 was $14.3 million. Trade working
capital provided $8.0 million in cash during the
233 days ended December 31, 2005 as an increase in
accounts receivable was more than offset by decreases in
inventory and an increase in accounts payable. Offsetting the
sources of cash from operating activities highlighted above was
a $98.4 million use of cash related to deferred income
taxes and a $4.7 million use of cash related to other
long-term assets.
Cash Flows
Used In Investing Activities
Comparison of
the Three Months Ended March 31, 2008 and the Three Months
Ended March 31, 2007
Net cash used in investing activities for the three months ended
March 31, 2008 was $26.2 million compared to
$107.4 million for the three months ended March 31,
2007. The decrease in investing activities for the three months
ended March 31, 2008 as compared to the three months ended
March 31, 2007 was the result of decreased capital
expenditures associated with various capital projects that
commenced in the first quarter of 2007 in conjunction with the
refinery turnaround.
Comparison of
the Year Ended December 31, 2007 and the Year Ended
December 31, 2006
Net cash used in investing activities for the year ended
December 31, 2007 was $268.6 million compared to
$240.2 million for the year ended December 31, 2006.
The increase in investing activities for the year ended
December 31, 2007 as compared to the year ended
December 31, 2006 was the result of increased capital
expenditures associated with various capital projects in our
petroleum business.
Net cash used in investing activities was $12.3 million for
the 174 days ended June 23, 2005 and
$730.3 million for the 233 days ended
December 31, 2005. Investing activities for the combined
period ended December 31, 2005 included $685.1 million
related to the Subsequent Acquisition. The other primary use of
cash for investing activities for the year ended
December 31, 2005 was approximately $57.4 million in
capital expenditures.
Year Ended
December 31, 2006 Compared to the 174 Days Ended
June 23, 2005 and the 233 Days Ended December 31,
2005.
Net cash used in investing activities for the year ended
December 31, 2006 was $240.2 million compared to
$12.3 million for the 174 days ended June 23,
2005 and $730.3 million for the 233 days ended
December 31, 2005. Investing activities for the year ended
December 31, 2006 was the result of a capital spending
increase associated with Tier II fuel compliance and other
capital expenditures. Investing activities for the combined
period ended December 31, 2005 included $685.1 million
related to the Subsequent Acquisition. The other primary use of
cash for investing activities for the year ended
December 31, 2005 was approximately $57.4 million in
capital expenditures.
128
Cash Flows
(Used in) Provided by Financing Activities
Comparison of
the Three Months Ended March 31, 2008 and the Three Months
Ended March 31, 2007
Net cash used for financing activities for the three months
ended March 31, 2008 was $3.4 million as compared to
net cash provided by financing activities of $29.0 million
for the three months ended March 31, 2007. During the three
months ended March 31, 2008, we paid $1.2 million of
scheduled principal payments and deferred $2.1 million of
initial public offering costs related to CVR Partners, LP. For
the three months ended March 31, 2007, the primary source
of cash was the result of borrowings drawn on our revolving
credit facility.
Comparison of
the Year Ended December 31, 2007 and the Year Ended
December 31, 2006
Net cash provided by financing activities for the year ended
December 31, 2007 was $111.3 million as compared to
net cash provided by financing activities of $30.8 million
for the year ended December 31, 2006. The primary sources
of cash for the year ended December 31, 2007 were obtained
through $399.6 million of proceeds associated with our
initial public offering. The primary uses of cash for the year
ended December 31, 2007 was $335.8 million of
long-term debt retirement and $2.5 million in payments of
financing costs. The primary sources of cash for the year ended
December 31, 2006 were obtained through a refinancing of
the Successors first and second lien credit facilities
into a new long term debt credit facility of
$1.075 billion, of which $775.0 million was
outstanding as of December 31, 2006. The
$775.0 million term loan under the credit facility was used
to repay approximately $527.7 million in first and second
lien debt outstanding, fund $5.5 million in prepayment
penalties associated with the second lien credit facility and
fund a $250.0 million cash distribution to Coffeyville
Acquisition LLC. Other sources of cash included
$20.0 million of additional equity contributions into
Coffeyville Acquisition LLC, which was subsequently contributed
to our operating subsidiaries, and $30.0 million of
additional delayed draw term loans issued under the first lien
credit facility. During this period, we also paid
$1.7 million of scheduled principal payments on the first
lien term loans.
For the combined period ended December 31, 2005, net cash
provided by financing activities was $660.0 million. The
primary sources of cash for the combined periods ended
December 31, 2005 related to the funding of
Successors acquisition of the assets on June 24, 2005
in the form of $500.0 million in long-term debt and
$227.7 million of equity. Additional equity of
$10.0 million was contributed into Coffeyville Acquisition
LLC subsequent to the aforementioned acquisition, which was
subsequently contributed to our operating subsidiaries, in order
to fund a portion of two discretionary capital expenditures at
our refining operations. Additional sources of funds during the
year ended December 31, 2005 were obtained through the
borrowing of $0.2 million in revolving loan proceeds, net
of $69.6 million of repayments. Offsetting these sources of
cash from financing activities during the year ended
December 31, 2005 were $24.6 million in deferred
financing costs associated with the first and second lien debt
commitments raised by Successor in connection with the
Subsequent Acquisition and a $52.2 million cash
distribution to Immediate Predecessor prior to the Subsequent
Acquisition. See Liquidity and Capital
Resources Debt.
Working
Capital
Working capital at March 31, 2008, was $21.5 million,
consisting of $622.5 million in current assets and
$601.0 million in current liabilities. Working capital at
December 31, 2007 was $10.7 million, consisting of
$570.2 million in current assets and $559.5 million in
current liabilities. In addition, we had available borrowing
capacity under our revolving credit facility of
$112.6 million at March 31, 2008. In the current crude
oil price environment, working capital is subject to substantial
variability from
week-to-
week and month-to-month.
Letters of
Credit
Our revolving credit facility provides for the issuance of
letters of credit. At March 31, 2008, there were
$37.4 million of irrevocable letters of credit outstanding,
including $5.8 million in support of certain environmental
obligators and $31.6 million to secure transportation
services for crude oil.
129
Capital and
Commercial Commitments
In addition to long-term debt, we are required to make payments
relating to various types of obligations. The following table
summarizes our minimum payments as of March 31, 2008
relating to long-term debt, operating leases, unconditional
purchase obligations and other specified capital and commercial
commitments for the five-year period following March 31,
2008 and thereafter.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
|
(in millions)
|
|
|
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(1)
|
|
$
|
488.0
|
|
|
$
|
3.7
|
|
|
$
|
4.8
|
|
|
$
|
4.8
|
|
|
$
|
4.7
|
|
|
$
|
4.7
|
|
|
$
|
465.3
|
|
Operating leases(2)
|
|
|
8.9
|
|
|
|
2.8
|
|
|
|
3.3
|
|
|
|
1.7
|
|
|
|
0.9
|
|
|
|
0.2
|
|
|
|
|
|
Unconditional purchase obligations(3)
|
|
|
582.3
|
|
|
|
20.8
|
|
|
|
28.2
|
|
|
|
55.8
|
|
|
|
53.9
|
|
|
|
51.3
|
|
|
|
372.3
|
|
Environmental liabilities(4)
|
|
|
8.8
|
|
|
|
2.6
|
|
|
|
0.7
|
|
|
|
1.6
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
3.3
|
|
Funded letter of credit fees(5)
|
|
|
10.1
|
|
|
|
3.4
|
|
|
|
4.5
|
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments(6)
|
|
|
142.0
|
|
|
|
20.2
|
|
|
|
26.6
|
|
|
|
26.3
|
|
|
|
26.1
|
|
|
|
25.9
|
|
|
|
16.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,240.1
|
|
|
$
|
53.5
|
|
|
$
|
68.1
|
|
|
$
|
92.4
|
|
|
$
|
85.9
|
|
|
$
|
82.4
|
|
|
$
|
857.8
|
|
Other Commercial Commitments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standby letters of credit(7)
|
|
$
|
37.4
|
|
|
$
|
37.4
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
(1)
|
|
Long-term debt amortization is based on the contractual terms of
our Credit Facility. We may be required to amend our Credit
Facility in connection with an offering by the Partnership. As
of March 31, 2008, $488.0 million was outstanding
under our credit facility. See Liquidity and
Capital Resources Debt.
|
|
(2)
|
|
The nitrogen fertilizer business leases various facilities and
equipment, primarily railcars, under non-cancelable operating
leases for various periods.
|
|
(3)
|
|
The amount includes (1) commitments under several
agreements in our petroleum operations related to pipeline
usage, petroleum products storage and petroleum transportation
and (2) commitments under an electric supply agreement with
the city of Coffeyville.
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(4)
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Environmental liabilities represents (1) our estimated
payments required by federal and/or state environmental agencies
related to closure of hazardous waste management units at our
sites in Coffeyville and Phillipsburg, Kansas and (2) our
estimated remaining costs to address environmental contamination
resulting from a reported release of UAN in 2005 pursuant to the
State of Kansas Voluntary Cleanup and Property Redevelopment
Program. We also have other environmental liabilities which are
not contractual obligations but which would be necessary for our
continued operations. See Business
Environmental Matters.
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(5)
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This amount represents the total of all fees related to the
funded letter of credit issued under our Credit Facility. The
funded letter of credit is utilized as credit support for the
Cash Flow Swap. See Quantitative and
Qualitative Disclosures About Market Risk Commodity
Price Risk.
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(6)
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Interest payments are based on interest rates in effect at
April 1, 2008 and assume contractual amortization payments.
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(7)
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Standby letters of credit include $5.8 million of letters
of credit issued in connection with environmental liabilities
and $31.6 million in letters of credit to secure
transportation services for crude oil.
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In addition to the amounts described in the above table, we owe
J. Aron approximately $123.7 million plus accrued interest
($5.8 million as of June 1, 2008) which will be due
August 31, 2008 and approximately $54.0 million which will
be due on July 8, 2008 for crude oil we settled or will
settle with respect to the quarter ending June 30, 2008
based on June 16, 2008 pricing. Also, if the Partnership
does not consummate an initial private or public offering by
October 24, 2009, the managing general partner of the
Partnership can require us to purchase the managing general
partner interest at fair market value until the earlier of
October 24, 2012 and the closing of the Partnerships
initial offering.
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Our ability to make payments on and to refinance our
indebtedness, to repay the amounts owed to J. Aron, to purchase
the Partnerships managing general partner interest if the
Partnerships managing general partner exercises its put
right, to fund planned capital expenditures and to satisfy our
other capital and commercial commitments will depend on our
ability to generate cash flow in the future. This, to a certain
extent, is subject to refining spreads, fertilizer margins,
receipt of distributions from the Partnership and general
economic financial, competitive, legislative, regulatory and
other factors that are beyond our control. Our business may not
generate sufficient cash flow from operations, and future
borrowings may not be available to us under our credit facility
(or other credit facilities we may enter into in the future) in
an amount sufficient to enable us to pay our indebtedness or to
fund our other liquidity needs. We may seek to sell additional
assets to fund our liquidity needs but may not be able to do so.
We may also need to refinance all or a portion of our
indebtedness on or before maturity. Our ability to refinance our
indebtedness is also subject to the availability of the credit
markets, which in recent periods have been extremely volatile
and have experienced significant increases in the cost of
financing. We may not be able to refinance any of our
indebtedness on commercially reasonable terms or at all.
Off-Balance Sheet
Arrangements
We do not have any off-balance sheet arrangements as
such term is defined within the rules and regulations of the SEC.
Recently Issued
Accounting Standards
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157,
Fair Value
Measurements
, which establishes a framework for measuring
fair value in GAAP and expands disclosures about fair value
measurements. SFAS 157 states that fair value is
the price that would be received to sell the asset or paid
to transfer the liability (an exit price), not the price that
would be paid to acquire the asset or received to assume the
liability (an entry price). The standards provisions
for financial assets and financial liabilities, which became
effective January 1, 2008, had no material impact on the
Companys financial position or results of operations. At
March 31, 2008, the only financial assets and financial
liabilities that are measured at fair value on a recurring basis
are the Companys derivative instruments. See Note 14
to our consolidated financial statements, Fair Value
Measurements, included elsewhere in this prospectus.
In February 2008, the FASB issued FASB Staff Position
157-2
which
defers the effective date of SFAS 157 for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in an entitys
financial statements on a recurring basis (at least annually).
The Company will be required to adopt SFAS 157 for these
nonfinancial assets and nonfinancial liabilities as of
January 1, 2009. Management believes the adoption of
SFAS 157 deferral provisions will not have a material
impact on the Companys financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,
The
Fair Value Option for Financial Assets and Financial
Liabilities
. Under this standard, an entity is required to
provide additional information that will assist investors and
other users of financial information to more easily understand
the effect of the Companys choice to use fair value on its
earnings. Further, the entity is required to display the fair
value of those assets and liabilities for which the Company has
chosen to use fair value on the face of the balance sheet. This
standard does not eliminate the disclosure requirements about
fair value measurements included in SFAS No. 107,
Disclosures about Fair Value of Financial Instruments
.
The provisions of SFAS 159 were effective for CVR as of
January 1, 2008. The Company did not elect the fair value
option under this standard upon adoption. Therefore, the
adoption of SFAS 159 did not impact the Companys
consolidated financial statements as of the quarter ended
March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
. This statement defines the
acquirer as the entity that obtains control of one or more
businesses in the business combination, establishes the
acquisition date as the date that the acquirer achieves control
and
131
requires the acquirer to recognize the assets acquired,
liabilities assumed and any non-controlling interest at their
fair values as of the acquisition date. This statement also
requires that acquisition-related costs of the acquirer be
recognized separately from the business combination and will
generally be expensed as incurred. CVR Energy will be required
to adopt this statement as of January 1, 2009. The impact
of adopting SFAS 141(R) will be limited to any future
business combinations for which the acquisition date is on or
after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting standards
for the non-controlling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a
non-controlling interest in a subsidiary is an ownership
interest in the consolidated entity that should be reported as
equity in the consolidated financial statements. SFAS 160
requires retroactive adoption of the presentation and disclosure
requirements for existing minority interests. All other
requirements of SFAS 160 must be applied prospectively.
SFAS 160 is effective for CVR beginning January 1,
2009. The Company is currently evaluating the potential impact
of the adoption of SFAS 160 on its consolidated financial
statements.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133
. This statement will change the disclosure
requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about how
and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
Statement 133 and its related interpretations, and how
derivative instruments and related hedged items affect an
entitys financial position, net earnings, and cash flows.
The Company will be required to adopt this statement as of
January 1, 2009. The adoption of SFAS 161 is not
expected to have a material impact on the Companys
consolidated financial statements.
The FASB recently issued final FASB Staff Position
(FSP)
No. APB 14-1
Accounting for Convertible Debt Instruments That May Be
Settled in Cash upon Conversion (Including Partial Cash
Settlement
. The FSP changes the accounting treatment
for convertible debt instruments that by their stated terms may
be settled in cash upon conversion, including partial cash
settlements, unless the embedded conversion option is required
to be separately accounted for as a derivative under
SFAS 133,
Accounting for Derivative Instruments and
Hedging Activities
. Under the FSP, cash settled convertible
securities will be separated into their debt and equity
components. The FSP specifies that issuers of such instruments
should separately account for the liability and equity
components in a manner that will reflect the entitys
nonconvertible debt borrowing rate when interest cost is
recognized in subsequent periods. The FSP is effective for
financial statements issued for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal
years and will require issuers of convertible debt that can be
settled in cash to record the additional expense incurred. The
Company is currently evaluating the FSP in conjunction with its
convertible debt offering.
Critical
Accounting Policies
We prepare our consolidated financial statements in accordance
with GAAP. In order to apply these principles, management must
make judgments, assumptions and estimates based on the best
available information at the time. Actual results may differ
based on the accuracy of the information utilized and subsequent
events. Our accounting policies are described in the notes to
our audited financial statements for the year ended
December 31, 2007 included elsewhere in this prospectus.
Our critical accounting policies, which are described below,
could materially affect the amounts recorded in our financial
statements.
Receivables
from Insurance
As of March 31, 2008, we have incurred total gross costs of
approximately of $154.5 million as a result of the 2007
flood and crude oil discharge. During this period, we have
maintained insurance
132
policies that were issued by a variety of insurers and which
covered various risks, such as property damage, interruption of
our business, environmental cleanup costs, and potential
liability to third parties for bodily injury or property damage.
Accordingly, as of March 31, 2008, we have recognized
receivables of approximately $107.2 million related to
these gross costs incurred that we believe are probable of
recovery from the insurance carriers under the terms of the
respective policies. As of March 31, 2008, we have
collected approximately $21.5 million of these receivables.
We are in the process of submitting our claims to, responding to
information requests from, and negotiating with the insurers
with respect to costs and damages related to the 2007 flood and
crude oil discharge. Our property insurers have raised a
question as to whether our facilities are principally located in
Zone A, which is subject to a $10 million
insurance limit for flood or Zone B which is
subject to a $300 million insurance limit for flood. We
have reached agreement with 32.5% of our property insurers that
our facilities are principally located in Zone B. Our remaining
property insurers have not, at this time, agreed to this
position. In addition, our primary environmental liability
insurance carrier has asserted that our pollution liability
claims are for cleanup, which is subject to a
$10 million sub-limit, rather than property
damage, which is covered to the limits of the policy. The
excess carrier has reserved its rights under the primary
carriers position. While we will vigorously contest the
primary carriers position, we believe that if that
position were upheld, our umbrella and excess Comprehensive
General Liability policies would continue to provide coverage
for these claims. Although each insurer has reserved its rights
under various policy exclusions and limitations and has cited
potential coverage defenses, we are vigorously pursuing our
insurance recovery claims. We expect that ultimate recovery will
be subject to negotiation and, if negotiation is unsuccessful,
litigation.
There is inherent uncertainty regarding the ultimate amount or
timing of the recovery of the insurance receivable because of
the difficulty in projecting the final resolution of our claims.
The difference between what we ultimately receive under our
insurance policies compared to the receivable we have recorded
could be material to our consolidated financial statements.
Long-Lived
Assets
We calculate depreciation and amortization on a straight-line
basis over the estimated useful lives of the various classes of
depreciable assets. When assets are placed in service, we make
estimates of what we believe are their reasonable useful lives.
CVR accounts for impairment of long-lived assets in accordance
with SFAS No. 144,
Accounting for the Impairment or
Disposal of Long-Lived Assets
. In accordance with
SFAS 144, CVR reviews long-lived assets (excluding
goodwill, intangible assets with indefinite lives, and deferred
tax assets) for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. Recoverability of assets to be held and used
is measured by a comparison of the carrying amount of an asset
to estimated undiscounted future net cash flows expected to be
generated by the asset. If the carrying amount of an asset
exceeds its estimated undiscounted future net cash flows, an
impairment charge is recognized for the amount by which the
carrying amount of the assets exceeds their fair value. Assets
to be disposed of are reported at the lower of their carrying
value or fair value less cost to sell. No impairment charges
were recognized for any of the periods presented.
Derivative
Instruments and Fair Value of Financial
Instruments
We use futures contracts, options, and forward contracts
primarily to reduce exposure to changes in crude oil prices,
finished goods product prices and interest rates to provide
economic hedges of inventory positions and anticipated interest
payments on long-term debt. Although management considers these
derivatives economic hedges, the Cash Flow Swap and our other
derivative instruments do not qualify as hedges for hedge
accounting purposes under SFAS No. 133,
Accounting
for Derivative Instruments and Hedging Activities
, and
accordingly are recorded at fair value in the balance sheet.
Changes in the fair value of these derivative instruments are
recorded into earnings as a component of other income (expense)
in the period of change. The estimated fair values of forward
and swap contracts are based on quoted market prices and
assumptions for the estimated forward yield curves of related
commodities in periods when quoted market prices are
unavailable. The Company recorded net
133
gains (losses) from derivative instruments of
($323.7) million, $94.5 million, $(282.0) million
and $(47.9) million in gain (loss) on derivatives for the
fiscal years ended December 31, 2005, 2006 and 2007 and the
three months ended March 31, 2008, respectively.
As of March 31, 2008, a $1.00 change in quoted prices for
the crack spreads utilized in the Cash Flow Swap would result in
a $32.6 million change to the fair value of derivative
commodity position and the same change to net income.
Environmental
Expenditures
Liabilities related to future remediation of contaminated
properties are recognized when the related costs are considered
probable and can be reasonably estimated. Estimates of these
costs are based upon currently available facts, existing
technology, site-specific costs, and currently enacted laws and
regulations. In reporting environmental liabilities, no offset
is made for potential recoveries. All liabilities are monitored
and adjusted as new facts or changes in law or technology occur.
Environmental expenditures are capitalized when such costs
provide future economic benefits. Changes in laws, regulations
or assumptions used in estimating these costs could have a
material impact to our financial statements. The amount recorded
for environmental obligations (exclusive of estimated
obligations associated with the crude oil discharge) at
March 31, 2008 totaled $7.7 million, including
$2.8 million included in current liabilities. Additionally,
at March 31, 2008, $1.0 million was included in
current liabilities for estimated future remediation obligations
arising from the crude oil discharge. This amount also included
estimated obligations to settle third party property damage
claims resulting from the crude oil discharge.
Income
Taxes
Income tax expense is estimated based on the projected effective
tax rate based upon future tax return filings. The amounts
anticipated to be reported in those filings may change between
the time the financial statements are prepared and the time the
tax returns are filed. Further, because tax filings are subject
to review by taxing authorities, there is also the risk that a
position on a tax return may be challenged by a taxing
authority. If the taxing authority is successful in asserting a
position different than that taken by us, differences in a tax
expense or between current and deferred tax items may arise in
future periods. Any of these differences which could have a
material impact on our financial statements would be reflected
in the financial statements when management considers them
probable of occurring and the amount reasonably capable of being
estimated.
Valuation allowances reduce deferred tax assets to an amount
that will more likely than not be realized. Managements
estimates of the realization of deferred tax assets is based on
the information available at the time the financial statements
are prepared and may include estimates of future income and
other assumptions that are inherently uncertain. No valuation
allowance is currently recorded, as we expect to realize our
deferred tax assets.
Consolidation
of Variable Interest Entities
In accordance with FIN No. 46R management has reviewed
the terms associated with our interests in the Partnership based
upon the partnership agreement. Management has determined that
the Partnership is treated as a variable interest entity and as
such has evaluated the criteria under FIN 46R to determine
that we are the primary beneficiary of the Partnership.
FIN 46R requires the primary beneficiary of a variable
interest entitys activities to consolidate the VIE.
FIN 46R defines a variable interest entity as an entity in
which the equity investors do not have substantive voting rights
and where there is not sufficient equity at risk for the entity
to finance its activities without additional subordinated
financial support. As the primary beneficiary, we absorb the
majority of the expected losses
and/or
receive a majority of the expected residual returns of the
VIEs activities.
We will need to reassess our investment in the Partnership from
time to time to determine whether we are the primary
beneficiary. If in the future we conclude that we are no longer
the primary beneficiary, we will be required to deconsolidate
the activities of the Partnership on a going forward basis. The
interest would then be recorded using the equity method and the
Partnership gross
134
revenues, expenses, net income, assets and liabilities as such
would not be included in our consolidated financial statements.
Quantitative
and Qualitative Disclosures About Market Risk
The risk inherent in our market risk sensitive instruments and
positions is the potential loss from adverse changes in
commodity prices and interest rates. None of our market risk
sensitive instruments are held for trading.
Commodity Price
Risk
Our petroleum business, as a manufacturer of refined petroleum
products, and the nitrogen fertilizer business, as a
manufacturer of nitrogen fertilizer products, all of which are
commodities, has exposure to market pricing for products sold in
the future. In order to realize value from our processing
capacity, a positive spread between the cost of raw materials
and the value of finished products must be achieved (i.e., gross
margin or crack spread). The physical commodities that comprise
our raw materials and finished goods are typically bought and
sold at a spot or index price that can be highly variable.
We use a crude oil purchasing intermediary which allows us to
take title and price of our crude oil at the refinery, as
opposed to the crude origination point, reducing our risk
associated with volatile commodity prices by shortening the
commodity conversion cycle time. The commodity conversion cycle
time refers to the time elapsed between raw material acquisition
and the sale of finished goods. In addition, we seek to reduce
the variability of commodity price exposure by engaging in
hedging strategies and transactions that will serve to protect
gross margins as forecasted in the annual operating plan.
Accordingly, we use financial derivatives to economically hedge
future cash flows (i.e., gross margin or crack spreads) and
product inventories. With regard to our hedging activities, we
may enter into, or have entered into, derivative instruments
which serve to:
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lock in or fix a percentage of the anticipated or planned gross
margin in future periods when the derivative market offers
commodity spreads that generate positive cash flows;
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hedge the value of inventories in excess of minimum required
inventories; and
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hedge the value of inventories held with respect to our rack
marketing business.
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Further, we intend to engage only in risk mitigating activities
directly related to our business.
Basis Risk.
The effectiveness of our
derivative strategies is dependent upon the correlation of the
price index utilized for the hedging activity and the cash or
spot price of the physical commodity for which price risk is
being mitigated. Basis risk is a term we use to define that
relationship. Basis risk can exist due to several factors
including time or location differences between the derivative
instrument and the underlying physical commodity. Our selection
of the appropriate index to utilize in a hedging strategy is a
prime consideration in our basis risk exposure.
Examples of our basis risk exposure are as follows:
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Time Basis In entering into over-the-counter swap
agreements, the settlement price of the swap is typically the
average price of the underlying commodity for a designated
calendar period. This settlement price is based on the
assumption that the underlying physical commodity will price
ratably over the swap period. If the commodity does not move
ratably over the periods then weighted average physical prices
will be weighted differently than the swap price as the result
of timing.
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Location Basis In hedging NYMEX crack spreads, we
experience location basis as the settlement of NYMEX refined
products (related more to New York Harbor cash markets) which
may be different than the prices of refined products in our
Group 3 pricing area.
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Price and Basis Risk Management
Activities.
The most significant derivative
position we have is our Cash Flow Swap. The Cash Flow Swap, for
which the underlying commodity is the crack spread, enabled us
to lock in a margin on the spread between the price of crude oil
and price of refined products at the execution date of the
agreement. We may look for opportunities to reduce the
135
effective position of the Cash Flow Swap by buying either
exchange-traded contracts in the form of futures contracts or
over-the-counter contracts in the form of commodity price swaps.
In addition, we may sell forward crack spreads when
opportunities exist to lock in a margin.
In the event our inventories exceed our target base level of
inventories, we may enter into commodity derivative contracts to
manage our price exposure to our inventory positions that are in
excess of our base level. Excess inventories are typically the
result of plant operations such as a turnaround or other plant
maintenance. The commodity derivative contracts are either
exchange-traded contracts in the form of futures contracts or
over-the-counter contracts in the form of commodity price swaps.
To reduce the basis risk between the price of products for Group
3 and that of the NYMEX associated with selling forward
derivative contracts for NYMEX crack spreads, we may enter into
basis swap positions to lock the price difference. If the
difference between the price of products on the NYMEX and Group
3 (or some other price benchmark as we may deem appropriate) is
different than the value contracted in the swap, then we will
receive from or owe to the counterparty the difference on each
unit of product contracted in the swap, thereby completing the
locking of our margin. An example of our use of a basis swap is
in the winter heating oil season. The risk associated with not
hedging the basis when using NYMEX forward contracts to fix
future margins is if the crack spread increases based on prices
traded on NYMEX while Group 3 pricing remains flat or decreases
then we would be in a position to lose money on the derivative
position while not earning an offsetting additional margin on
the physical position based on the Group 3 pricing.
As of March 31, 2008, a $1.00 change in quoted futures
price for the crack spreads described in the first bullet point
would result in a $36.2 million change to the fair value of
the derivative commodity position and the same change in net
income.
Interest Rate
Risk
As of March 31, 2008, all of our $488.0 million of
outstanding term debt was at floating rates. An increase of 1.0%
in the LIBOR rate would result in an increase in our interest
expense of approximately $4.9 million per year.
In an effort to mitigate the interest rate risk highlighted
above and as required under our then-existing first and second
lien credit agreements, we entered into several interest rate
swap agreements in 2005. These swap agreements were entered into
with counterparties that we believe to be creditworthy. Under
the swap agreements, we pay fixed rates and receive floating
rates based on the three-month LIBOR rates, with payments
calculated on the notional amounts set forth in the table below.
The interest rate swaps are settled quarterly and marked to
market at each reporting date.
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Effective
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Termination
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Fixed
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Notional Amount
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Date
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Date
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Rate
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$250.0 million
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March 31, 2008
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March 30, 2009
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4.195
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%
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$180.0 million
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March 31, 2009
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March 30, 2010
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4.195
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%
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$110.0 million
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March 31, 2010
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June 29, 2010
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4.195
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%
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We have determined that these interest rate swaps do not qualify
as hedges for hedge accounting purposes. Therefore, changes in
the fair value of these interest rate swaps are included in
income in the period of change. Net realized and unrealized
gains or losses are reflected in the gain (loss) for derivative
activities at the end of each period. For the year ended
December 31, 2007, we had $4.8 million of realized and
unrealized losses on these interest rate swaps. For the three
months ended March 31, 2008 and March 31, 2007, we had
$5.6 million and $0.6 million of realized and
unrealized losses on these interest rate swaps, respectively.
136
INDUSTRY
OVERVIEW
Oil Refining
Industry
Oil refining is the process of separating the wide spectrum of
hydrocarbons present in crude oil, and in certain processes,
modifying the constituent molecular structures, for the purpose
of converting them into marketable finished, or refined,
petroleum products optimized for specific end uses. Refining is
primarily a margin-based business where both the feedstocks (the
petroleum products such as crude oil or natural gas liquids that
are processed and blended into refined products) and the refined
finished products are commodities. It is important for a
refinery to maintain high throughput rates (the volume per day
processed through the refinery) and capacity utilization given
the substantial fixed component in the total operating costs.
There are also material variable costs associated with the fuel
and by-product components that become increasingly expensive as
crude prices increase. The refiners goal is to achieve
highest profitability by maximizing the yields of high value
finished products and by minimizing feedstock and operating
costs.
According to the Energy Information Administration, or the EIA,
as of January 1, 2007, there were 145 oil refineries
operating in the United States, with the 15 smallest each having
a capacity of 12,500 bpd or less, and the 10 largest having
capacities ranging from 306,000 to 562,500 bpd. Refiners
typically are structured as part of a fully or partially
integrated oil company, or as an independent entity, such as our
Company.
Refining
Margins
A variety of so called crack spread indicators are
used to track the profitability of the refining industry. Among
those of most relevance to our refinery are (1) the
gasoline crack spread, (2) the heat crack spread, and
(3) the 2-1-1 crack spread. The gasoline crack spread is
the simple difference in per barrel value between reformulated
gasoline (gasoline with compounds or properties which meet the
requirements of the reformulated gasoline regulations) in New
York Harbor as traded on the New York Mercantile Exchange, or
NYMEX, and the NYMEX prompt price of West Texas Intermediate, or
WTI, crude oil on any given day. This provides a measure of the
profitability when producing gasoline. The heat crack spread is
the similar measure of the price of Number 2 heating oil in New
York Harbor as traded on the NYMEX, relative to the value of WTI
crude which provides a measure of the profitability of producing
distillates. The 2-1-1 crack spread is a composite spread that
assumes for simplification and comparability purposes that for
every two barrels of WTI consumed, a refinery produces one
barrel of gasoline and one barrel of heating oil; the spread is
based on the NYMEX price and delivery of gasoline and heating
oil in New York Harbor. The 2-1-1 crack spread provides a
measure of the general profitability of a medium high complexity
refinery on the day that the spread is computed. The ability of
a crack spread to measure profitability is affected by the
absolute crude price.
Our refinery uses a consumed 2-1-1 crack spread to measure its
specific daily performance in the market. The consumed 2-1-1
crack spread assumes the same relative production of gasoline
and heating oil from crude, so like the NYMEX based 2-1-1 crack
spread, it has an inherent inaccuracy because the refinery does
not produce exactly two barrels of high valued products for each
two barrels of crude oil, and the relative proportions of
gasoline to heating oil will vary somewhat from the 1:1
relationship. However, the consumed 2-1-1 crack spread is an
economically more accurate measure of performance than the NYMEX
based 2-1-1 crack spread since the crude price used represents
the price of our actual charged crude slate and is based on the
actual sale values in our marketing region, rather than on New
York Harbor NYMEX numbers. Average 2-1-1 crack spreads vary from
region to region depending on the supply and demand balances of
crude oils and refined products and can vary seasonally and from
year to year reflecting more macroeconomic factors.
Although refining margins, the difference between the per barrel
prices for refined products and the cost of crude oil, can be
volatile during short term periods of time due to seasonality of
demand,
137
refinery outages, extreme weather conditions and fluctuations in
levels of refined product held in storage, longer-term averages
have steadily increased over the last 10 years as a result
of the improving fundamentals for the refining industry. For
example, the NYMEX based 2-1-1 crack spread averaged $3.88 per
barrel from 1994 through 1998 compared to $11.02 per barrel from
2004 to March 31, 2008. The following chart shows a rolling
average of the NYMEX based 2-1-1 crack spread from 1994 through
March 31, 2008:
Source:
Platts
There are a number of reasons high crude oil costs have a
negative impact on our earnings. Less than 100% of the crude oil
we purchase can actually be turned into profitable
transportation fuels; the conversion process also produces less
valuable byproducts such as pet coke, slurry and sulfur. These
byproducts are less valuable than transportation fuels, and
their sales prices have not increased in proportion to crude oil
prices. Therefore, as the price on crude oil increases our loss
on byproduct sales increases, which results in a reduction in
earnings. Also, as discussed previously, as crack spreads
increase in absolute terms in connection with higher crude
prices, the Company realizes increasing losses on the Cash Flow
Swap.
Refining
Market Trends
The supply and demand fundamentals of the domestic refining
industry have improved since the 1990s and are expected to
remain favorable as the growth in demand for refined products
continues to exceed increases in refining capacity. Over the
next two decades, the EIA projects that U.S. demand for
refined products will grow at an average of 0.8% per year
compared to total domestic refining capacity growth of only 0.3%
per year. Substantially all of the projected demand growth is
expected to come from the increased consumption of
transportation fuels.
High capital costs, historical excess capacity and environmental
regulatory requirements have limited the construction of new
refineries in the United States over the past 30 years.
According to the EIA, domestic refining capacity decreased
approximately 6% between January 1981 and January 2007 from
18.6 million bpd to 17.4 million bpd, as more than 175
generally small and unsophisticated refineries that were unable
to process heavy crude into a marketable product mix have been
shut down, and no new major refinery has been built in the
United States. The implementation of the federal Tier II
low sulfur fuel regulations is expected to further reduce
existing refining capacity.
As reflected within the U.S. Days Forward Supply and the
U.S. Mogas Inventory statistics provided by the EIA, the
gasoline available for consumption in the United States has
declined year after year. This trend is in most part
attributable to a steady increase in demand that has not been
matched by an equal increase in supply. Although existing
refiners are improving their utilization rates, the total number
of refiners has declined. As a result, the U.S. has been
dependent on imported fuels to meet domestic
138
demand while the global supply which has historically been
available for importation has been subject to increasing
worldwide demand. With this reduction in days of available
supply, we believe the U.S. will occasionally experience
periods of little or no supply of gasoline in various markets as
the supply and distribution system continues to strain to match
available inventory with consumer demand.
In order to meet the increasing demands of the market,
U.S. refineries have pursued efficiency measures to improve
existing production levels. These efficiency measures and other
initiatives, generally known as capacity creep, have raised
productive capacity of existing refineries by approximately 1%
per year since 1993. According to the EIA, between 1981 and
2004, refinery utilization increased from 69% to 93%. Over the
next 25 years, the EIA projects that utilization will
remain high relative to historic levels, ranging from 90% to 95%
of design capacity.
The price discounts available to refiners of heavy sour crude
oil have widened as many refiners have turned to sweeter and
lighter crude oils to meet lower sulfur fuel specifications,
which has resulted in increasing the surplus of sour and heavy
crude oils. As the global economy has improved, worldwide crude
oil demand has increased, and OPEC and other producers have
tended to incrementally produce more of the sour or heavier
crude oil varieties. We believe that the combination of
increasing worldwide supplies of lower cost sour and heavy crude
oils and increasing demand for sweet and light crude oils will
provide a cost advantage to refineries with configurations that
are able to process sour crude oils.
We expect refined products that meet new and evolving fuel
specifications will account for an increasing share of total
fuel demand, which will benefit refiners who are able to
efficiently produce these fuels. As part of the Clean Air Act,
major metropolitan areas in the United States with air pollution
problems must require the sale and use of reformulated gasoline
meeting certain environmental standards in their jurisdictions.
Boutique fuels, such as low vapor pressure Kansas City gasoline,
enable refineries capable of producing such refined products to
achieve higher margins.
Due to the ongoing supply and demand imbalance, the United
States continues to be a net refined products importer. Imports,
largely from northwest Europe and Asia, accounted for over 12%
139
of total U.S. consumption in 2005. The level of imports
generally increases during periods when refined product prices
in the United States are materially higher than in Europe and
Asia.
Based on the strong fundamentals for the global refining
industry, capital investments for refinery expansions and new
refineries in international markets have increased during the
recent year. However, the competitive threat faced by domestic
refiners is limited by U.S. fuel specifications and
increasing foreign demand for refined products, particularly for
light transportation fuels.
Certain regional markets in the United States, such as the
mid-continent region where our refinery is located, do not have
the necessary refining capacity to produce a sufficient amount
of refined products to meet area demand and therefore rely on
pipelines and other modes of transportation for incremental
supply from other regions of the United States and globally. The
shortage of refining capacity is a factor that results in local
refiners serving these markets earning generally higher margins
on their product sales than those who have to transport their
products to this region over long distances.
Notwithstanding the trends described above, the refining
industry is cyclical and volatile and has undergone downturns in
the past. See Risk Factors.
Refinery
Locations
A refinerys location can have an important impact on its
refining margins because location can influence access to
feedstocks and efficient distribution. There are five regions in
the United States, the Petroleum Administration for Defense
Districts (PADDs), that have historically experienced varying
levels of refining profitability due to regional market
conditions. Refiners located in the U.S. Gulf Coast region
operate in a highly competitive market due to the fact that this
region (PADD III) accounts for approximately 38% of the
total number of U.S. refineries and approximately 48% of
the countrys refining capacity. PADD I represents the East
Coast, PADD IV the Rocky Mountains and PADD V is the West Coast.
Coffeyville operates in the Midwest (PADD II) region of the
US. In 2007, demand for gasoline and distillates (primarily
diesel fuels, kerosene and jet fuel) exceeded refining
production in the mid-continent region, which created a need to
import a significant portion of the regions requirement
for petroleum products from the U.S. Gulf Coast and other
regions. The deficit of local refining capacity benefits local
refined product pricing and could generally lead to higher
margins for local refiners such as our company.
140
Nitrogen
Fertilizer Industry
Plant
Nutrition and Nitrogen Fertilizers
Commercially produced nitrogen fertilizers provide primary
nutrients for plant growth in a form that is readily absorbable.
Nitrogen is an essential element for plant growth and vigor and
is the most important element for increasing yields in crop
plants. Nitrogen and other plant nutrients are found naturally
in organic matter and soil materials but are depleted by
intensive crop production and harvesting. Replenishing nitrogen
through application of commercial fertilizers is the most widely
used way of sustaining or increasing crop yields. Two primary
sources of plant nutrients are manufactured fertilizers and
organic manures. Farmers determine the types, quantity and
proportions of fertilizer to apply depending upon crop type,
soil and weather conditions, regional farming practices,
fertilizer and crop prices and other factors.
Nitrogen, which typically accounts for approximately 60% of
worldwide fertilizer consumption in any planting season, is an
essential element for most organic compounds in plants as it
promotes protein formation and is a major component of
chlorophyll, which helps to promote green healthy growth and
high yields. There are no substitutes for nitrogen fertilizers
in the cultivation of high-yield crops such as corn, which on
average requires
100-160
pounds of nitrogen for each acre of plantings. The four
principal nitrogen based fertilizer products are:
Ammonia.
Ammonia is used in limited
quantities as a direct application fertilizer, and is primarily
used as a building block for other nitrogen products, including
intermediate products for industrial applications and finished
fertilizer products. Ammonia, consisting of 82% nitrogen, is
stored either as a refrigerated liquid at minus 27 degrees, or
under pressure if not refrigerated. It is gaseous at ambient
temperatures and is injected into the soil as a gas. The direct
application of ammonia requires farmers to make a considerable
investment in pressurized storage tanks and injection machinery,
and can take place only under a narrow range of ambient
conditions.
Urea.
Urea is formed by reacting
ammonia with
CO
2
at high pressure. From the warm urea liquid produced in the
first, wet stage of the process, the finished product is mostly
produced as a coated, granular solid containing 46% nitrogen and
suitable for use in bulk fertilizer blends containing the other
two principal fertilizer nutrients, phosphate and potash. We do
not produce merchant urea.
Ammonium Nitrate.
Ammonium nitrate is
another dry, granular form of nitrogen based fertilizer. It is
produced by converting ammonia to nitric acid in the presence of
a platinum catalyst reaction, then further reacting the nitric
acid with additional volumes of ammonia to form ammonium
nitrate. We do not produce this product.
Urea Ammonium Nitrate Solution.
Urea
can be combined with ammonium nitrate solution to make liquid
nitrogen fertilizer (urea ammonium nitrate or UAN). These
solutions contain 32% nitrogen and are easy to store and
transport.
In 2007, we produced approximately 326,662 tons of ammonia, of
which approximately 72% was upgraded into approximately 576,888
tons of UAN.
Ammonia
Production Technology Advantages of Pet Coke
Gasification
Ammonia is produced by reacting gaseous nitrogen with hydrogen
at high pressure and temperature in the presence of a catalyst.
Traditionally, nearly all hydrogen produced for the manufacture
of nitrogen based fertilizers was produced by reforming natural
gas at a high temperature and pressure in the presence of water
and a catalyst. This process consumes a significant amount of
natural gas and as a result production costs increase
significantly as natural gas prices increase.
Alternatively, hydrogen for ammonia can also be produced by
gasifying pet coke. Pet coke is a coal-like substance that is
produced during the petroleum refining process. The pet coke
gasification process, which the nitrogen fertilizer business
commercially employs at its fertilizer plant, the only such
plant in North America, takes advantage of the large cost
differential between pet coke and
141
natural gas in current markets. The nitrogen fertilizer
plants pet coke gasification process allows it to use
approximately 1% of the natural gas relative to other nitrogen
based fertilizer facilities that are heavily dependent upon
natural gas and are thus heavily impacted by natural gas price
swings. The nitrogen fertilizer business also benefits from the
ready availability of pet coke supply from our refinery plant.
Pet coke is a refinery by-product which if not used in the
fertilizer plant would otherwise be sold as fuel, generating
less value to the company.
Fertilizer
Consumption Trends
Global demand for fertilizers typically grows at predictable
rates and tends to correspond to growth in grain production and
pricing. Global fertilizer demand is driven in the long-term
primarily by population growth, increases in disposable income
and associated improvements in diet. Short-term demand depends
on world economic growth rates and factors creating temporary
imbalances in supply and demand. These factors include weather
patterns, the level of world grain stocks relative to
consumption, agricultural commodity prices, energy prices, crop
mix, fertilizer application rates, farm income and temporary
disruptions in fertilizer trade from government intervention,
such as changes in the buying patterns of large countries like
China or India. According to the International Fertilizer
Industry Association, or IFA, from 1960 to 2005, global
fertilizer demand has grown 3.7% annually and global nitrogen
demand has grown at a faster rate of 4.8% annually. According to
the IFA, during that
45-year
period, North American fertilizer demand has grown 2.4% annually
with North American nitrogen fertilizer demand growing at a
faster rate of 3.3% annually.
According to the United States Department of Agriculture, or
USDA, U.S. farmers planted 92.9 million acres of corn
in 2007, exceeding the 2006 planted area by 19 percent.
This increase was driven in large part by ethanol demand. The
actual planted acreage is the highest on record since 1944, when
farmers planted 95.5 million acres of corn. Farmers in
nearly all states increased their planted corn acreage in 2007.
State records were established in Illinois, Indiana, Minnesota
and North Dakota, while Iowa led all states in total planted
corn acres. A net effect of these additional planted acres was
to increase the demand for nitrogen fertilizers by over one
million tons. This equates to an annual increase of
3.3 million tons of UAN, or approximately 5 times the
nitrogen fertilizer plants total UAN production. The USDA
is forecasting as of March 2008 that total U.S. planted
corn acreage in 2008 will decline to 86 million acres.
Despite this decrease, Blue Johnson estimates that nitrogen
fertilizer consumption by farm users in 2008 will increase by
one million tons due to the need to correct for under
fertilization of corn in 2007, a forecasted increase in total
planted wheat acreage and very strong crop prices. This
estimated increase in nitrogen usage translates into an annual
increase of 3.3 million tons of UAN, or approximately five
times the nitrogen fertilizer business total 2008
estimated UAN production.
The Farm Belt
Nitrogen Market
The majority of the nitrogen fertilizer business product
shipments target freight advantaged destinations located in the
U.S. farm belt. The farm belt refers to the states of
Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska,
North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.
Because shipping ammonia requires refrigerated or pressured
containers and UAN is more than 65% water, transportation cost
is substantial for ammonia and UAN producers and importers. As a
result, locally based fertilizer producers, such as the nitrogen
fertilizer business, enjoy a distribution cost advantage over
U.S. Gulf Coast ammonia and UAN producers and importers.
Southern Plains spot ammonia and corn belt UAN 32 prices
averaged $337/ton and $201/ton, respectively, for the
142
2003 through 2007 period, based on data provided by Blue
Johnson. The volumes of ammonia and UAN sold into certain farm
belt markets in 2007 are set forth in the table below:
2005-2007
Average U.S. Ammonia and UAN Demand in Selected Mid-continent
Areas
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
UAN 32
|
|
State
|
|
Quantity
|
|
|
Quantity(1)
|
|
|
|
(thousand tons
|
|
|
|
per year)
|
|
|
Texas
|
|
|
2,125
|
|
|
|
850
|
|
Oklahoma
|
|
|
95
|
|
|
|
200
|
|
Kansas
|
|
|
395
|
|
|
|
690
|
|
Missouri
|
|
|
325
|
|
|
|
230
|
|
Iowa
|
|
|
710
|
|
|
|
900
|
|
Nebraska
|
|
|
425
|
|
|
|
1,150
|
|
Minnesota
|
|
|
310
|
|
|
|
200
|
|
|
|
|
(1)
|
|
UAN 32, which consists of 45% ammonium nitrate, 35% urea and 20%
water, contains 32% nitrogen by weight and is the most common
grade of UAN sold in the United States.
Source: Blue
Johnson
|
Fertilizer
Pricing Trends
The nitrogen fertilizer industry is cyclical and relatively
volatile, reflecting the commodity nature of ammonia and the
major finished fertilizer products (e.g., urea). Although
domestic industry-wide sales volumes of nitrogen based
fertilizers vary little from one fertilizer season to the next
due to the need to apply nitrogen every year to maintain crop
yields, in the normal course of business industry participants
are exposed to fluctuations in supply and demand, which can have
significant effects on prices across all participants
commodity business areas and products and, in turn, their
operating results and profitability. Changes in supply can
result from capacity additions or reductions and from changes in
inventory levels. Demand for fertilizer products is dependent on
demand for crop nutrients by the global agricultural industry,
which, in turn, depends on, among other things, weather
conditions in particular geographical regions. Periods of high
demand, high capacity utilization and increasing operating
margins tend to result in new plant investment, higher crop
pricing and increased production until supply exceeds demand,
followed by periods of declining prices and declining capacity
utilization, until the cycle is repeated. Due to dependence of
the prevalent nitrogen fertilizer technology on natural gas, the
marginal cost and pricing of fertilizer products also tend to
exhibit positive correlation with the price of natural gas.
Strong industry fundamentals have led current demand for
nitrogen fertilizers to all time highs. US corn inventories at
the end of the
2008-2009
fertilizer year are projected to be at 673 million bushels,
which is the lowest level since
1995-1996.
Corn prices are at record high levels, and corn planting for
2008-2009
is
projected to be higher than
2007-2008.
Nitrogen fertilizer prices are at record high levels due to
increased demand and increasing worldwide natural gas prices. In
addition, nitrogen fertilizer prices have been decoupled from
their historical correlation with natural gas prices in recent
years and increased substantially more than natural gas prices
in 2007 and 2008 (based on data provided by Blue Johnson). The
quest for healthier lives and better diets in developing
countries is a primary driving factor behind the increased
global demand for fertilizers. As of June 16, 2008, our
order book for UAN is 367,825 tons at an average netback price
of $326.56 per ton and 34,898 tons of ammonia at an average
netback price of $620.61.
143
The historical average annual U.S. corn belt ammonia and
UAN 32 spot prices as well as natural gas and crude oil prices
are detailed in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Natural Gas
|
|
|
WTI
|
|
|
Ammonia
|
|
|
UAN 32
|
|
|
|
($/million btu)
|
|
|
($/bbl)
|
|
|
($/ton)
|
|
|
($/ton)
|
|
|
1990
|
|
|
1.78
|
|
|
|
24.53
|
|
|
|
125
|
|
|
|
90
|
|
1991
|
|
|
1.53
|
|
|
|
21.55
|
|
|
|
130
|
|
|
|
97
|
|
1992
|
|
|
1.73
|
|
|
|
20.57
|
|
|
|
134
|
|
|
|
95
|
|
1993
|
|
|
2.11
|
|
|
|
18.43
|
|
|
|
139
|
|
|
|
102
|
|
1994
|
|
|
1.94
|
|
|
|
17.16
|
|
|
|
197
|
|
|
|
108
|
|
1995
|
|
|
1.69
|
|
|
|
18.38
|
|
|
|
238
|
|
|
|
132
|
|
1996
|
|
|
2.50
|
|
|
|
22.01
|
|
|
|
217
|
|
|
|
129
|
|
1997
|
|
|
2.48
|
|
|
|
20.59
|
|
|
|
220
|
|
|
|
116
|
|
1998
|
|
|
2.16
|
|
|
|
14.43
|
|
|
|
162
|
|
|
|
96
|
|
1999
|
|
|
2.32
|
|
|
|
19.26
|
|
|
|
145
|
|
|
|
86
|
|
2000
|
|
|
4.32
|
|
|
|
30.28
|
|
|
|
208
|
|
|
|
115
|
|
2001
|
|
|
4.04
|
|
|
|
25.92
|
|
|
|
262
|
|
|
|
144
|
|
2002
|
|
|
3.37
|
|
|
|
26.19
|
|
|
|
191
|
|
|
|
108
|
|
2003
|
|
|
5.49
|
|
|
|
31.03
|
|
|
|
292
|
|
|
|
141
|
|
2004
|
|
|
6.18
|
|
|
|
41.47
|
|
|
|
326
|
|
|
|
170
|
|
2005
|
|
|
9.02
|
|
|
|
56.58
|
|
|
|
394
|
|
|
|
210
|
|
2006
|
|
|
6.98
|
|
|
|
66.09
|
|
|
|
379
|
|
|
|
196
|
|
2007
|
|
|
7.12
|
|
|
|
72.36
|
|
|
|
469
|
|
|
|
290
|
|
2008 (through May)
|
|
|
9.77
|
|
|
|
106.54
|
|
|
|
681
|
|
|
|
377
|
|
Source: Bloomberg
(natural gas and WTI) and Blue Johnson (ammonia and
UAN)
144
BUSINESS
We are an independent refiner and marketer of high value
transportation fuels and, through a limited partnership, a
producer of ammonia and UAN fertilizers. We are one of only
seven petroleum refiners and marketers in within the
mid-continent region (Kansas, Oklahoma, Missouri, Nebraska and
Iowa). The nitrogen fertilizer business is the only operation in
North America that uses a coke gasification process, and at
current natural gas and pet coke prices, the nitrogen fertilizer
business is the lowest cost producer and marketer of ammonia and
UAN fertilizers in North America.
Our petroleum business includes a 115,000 bpd complex full
coking medium-sour crude refinery in Coffeyville, Kansas. In
addition, our supporting businesses include (1) a crude oil
gathering system serving central Kansas, northern Oklahoma and
southwestern Nebraska, (2) storage and terminal facilities
for asphalt and refined fuels in Phillipsburg, Kansas,
(3) a 145,000 bpd pipeline system that transports
crude oil to our refinery and associated crude oil storage tanks
with a capacity of approximately 1.2 million barrels and
(4) a rack marketing division supplying product through
tanker trucks directly to customers located in close geographic
proximity to Coffeyville and Phillipsburg and to customers at
throughput terminals on Magellan Midstream Partners L.P.s
refined products distribution systems. In addition to rack sales
(sales which are made at terminals into third party tanker
trucks), we make bulk sales (sales through third party
pipelines) into the mid-continent markets via Magellan and into
Colorado and other destinations utilizing the product pipeline
networks owned by Magellan, Enterprise Products Partners L.P.
and NuStar Energy L.P. Our refinery is situated approximately
100 miles from Cushing, Oklahoma, one of the largest crude
oil trading and storage hubs in the United States, served by
numerous pipelines from locations including the U.S. Gulf
Coast and Canada, providing us with access to virtually any
crude variety in the world capable of being transported by
pipeline.
The nitrogen fertilizer business, consists of a nitrogen
fertilizer manufacturing facility comprised of (1) a 1,225
ton-per-day
ammonia unit, (2) a 2,025
ton-per-day
UAN unit and (3) an 84 million standard cubic foot per
day gasifier complex. We are currently enjoying unprecedented
fertilizer prices which have contributed favorably to our
earnings. The nitrogen fertilizer business is the only operation
in North America that utilizes a coke gasification process to
produce ammonia (based on data provided by Blue Johnson). In
2007, approximately 72% of the ammonia produced by the
fertilizer plant was further upgraded to UAN fertilizer (a
solution of urea, ammonium nitrate and water used as a
fertilizer). By using pet coke (a coal-like substance that is
produced during the refining process) instead of natural gas as
a primary raw material, at current natural gas and pet coke
prices the nitrogen fertilizer business is the lowest cost
producer and marketer of ammonia and UAN fertilizers in North
America. Furthermore, on average during the last four years,
over 75% of the pet coke utilized by the fertilizer plant was
produced and supplied to the fertilizer plant as a by-product of
our refinery. As such, the nitrogen fertilizer business benefits
from high natural gas prices, as fertilizer prices generally
increase with natural gas prices, without a directly related
change in cost (because pet coke rather than natural gas is used
as a primary raw material).
We have two business segments: petroleum and nitrogen
fertilizer. We generated combined net sales of
$2.4 billion, $3.0 billion and $3.0 billion and
operating income of $270.8 million, $281.6 million and
$186.6 million for the fiscal years ended December 31,
2005, 2006 and 2007, respectively. Our petroleum business
generated $2.3 billion, $2.9 billion and
$2.8 billion of our combined net sales, respectively, over
these periods, with the nitrogen fertilizer business generating
substantially all of the remainder. In addition, during these
periods, our petroleum business contributed $199.7 million,
$245.6 million and $144.9 million, respectively, of
our combined operating income with substantially all of the
remainder contributed by the nitrogen fertilizer business. For
the three months ended March 31, 2008, we generated
combined net sales of $1.22 billion and operating income of
$87.4 million. Our petroleum business generated
$1.17 billion of our combined net sales and
$63.6 million of our combined operating income during this
period, with substantially all of the remainder contributed by
the nitrogen fertilizer business.
145
Our Competitive
Strengths
Regional Advantage and Strategic Asset
Location.
Our refinery is located in the
southern portion of the PADD II Group 3 distribution
area. Because refined product demand in this area exceeds
production, the region has historically required U.S. Gulf
Coast imports to meet demand. We estimate that this favorable
supply/demand imbalance combined with our lower pipeline
transportation cost as compared to the U.S. Gulf Coast
refiners has allowed us to generate refining margins, as
measured by the 2-1-1 crack spread, that have exceeded
U.S. Gulf Coast refining margins by approximately $2.14 per
barrel on average for the last four years. The 2-1-1 crack
spread is a general industry standard that approximates the per
barrel refining margin resulting from processing two barrels of
crude oil to produce one barrel of gasoline and one barrel of
heating oil.
In addition, the nitrogen fertilizer business is geographically
advantaged to supply nitrogen fertilizer products to markets in
Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without
incurring intermediate transfer, storage, barge or pipeline
freight charges. Because the nitrogen fertilizer business does
not incur these costs, this geographic advantage provides it
with a distribution cost advantage over competitors not located
in the farm belt who transport ammonia and UAN from the
U.S. Gulf Coast, based on recent freight rates and pipeline
tariffs for U.S. Gulf Coast importers.
Access to and Ability to Process Multiple Crude
Oils.
Since June 2005 we have significantly
expanded the variety of crude grades processed in any given
month and have reduced our acquisition cost of crude relative to
WTI by approximately $1.50 per barrel in 2006 compared to 2005.
While our proximity to the Cushing crude oil trading hub
minimizes the likelihood of an interruption to our supply, we
intend to further diversify our sources of crude oil. Among
other initiatives in this regard, we maintain capacity on the
Spearhead pipeline, owned by CCPS Transportation, LLC (which is
ultimately owned by Enbridge), which connects Chicago to the
Cushing hub. We have also committed to additional pipeline
capacity on the proposed Keystone pipeline project currently
under development by TransCanada Keystone Pipeline, LP which
will provide us with access to incremental oil supplies from
Canada. We also own and operate a crude gathering system serving
northern Oklahoma, central Kansas and southwestern Nebraska,
which allows us to acquire quality crudes at a discount to WTI.
High Quality, Modern Refinery with Solid Track
Record.
Our refinerys complexity allows
us to optimize the yields (the percentage of refined product
that is produced from crude and other feedstocks) of higher
value transportation fuels (gasoline and distillate), which
currently account for approximately 94% of our liquid production
output. Complexity is a measure of a refinerys ability to
process lower quality crude in an economic manner; greater
complexity makes a refinery more profitable. From 1995 through
March 31, 2008, we have invested approximately
$725 million to modernize our oil refinery and to meet more
stringent U.S. environmental, health and safety
requirements. As a result, we have achieved significant
increases in our refinery crude throughput rate, from an average
of less than 90,000 bpd prior to June 2005 to an average of
over 102,000 bpd in the second quarter of 2006, over
94,500 bpd for all of 2006 and over 110,000 bpd in the
fourth quarter of 2007 with maximum daily rates in excess of
120,000 bpd for the fourth quarter of 2007.
Unique Coke Gasification Fertilizer
Plant.
The nitrogen fertilizer plant,
completed in 2000, is the newest fertilizer facility in North
America and the only one of its kind in North America using a
pet coke gasification process to produce ammonia. While this
facility is unique to North America, gasification technology has
been in use for over 50 years in various industries to
produce fuel, chemicals and other products from carbon-based
source materials. Because it uses significantly less natural gas
in the manufacture of ammonia than other domestic nitrogen
fertilizer plants, with the currently high price of natural gas
the nitrogen fertilizer business feedstock cost per ton
for ammonia is considerably lower than that of its natural
gas-based fertilizer plant competitors. We estimate that the
facilitys production cost advantage over U.S. Gulf
Coast ammonia producers is sustainable at natural gas prices as
low as $2.50 per MMBtu (at June 16, 2008, the price of
natural gas was $12.93 per MMBtu).
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Near Term Internal Expansion
Opportunities.
Since June 2005, we have
identified and developed several significant capital
improvements primarily aimed at (1) expanding refinery
capacity, (2) enhancing operating reliability and
flexibility, (3) complying with more stringent
environmental, health and safety standards and
(4) improving our ability to process heavy sour crude
feedstock varieties. With the substantial completion of
approximately $522 million of significant capital
improvements (including $170 million in expenditures for
our refinery expansion project, excluding $3.7 million in
related capitalized interest), we expect to significantly
enhance the profitability of our refinery during periods of high
crack spreads while enabling the refinery to operate more
profitably at lower crack spreads than is currently possible.
The spare gasifier at the nitrogen fertilizer plant was expanded
in 2006, increasing ammonia production by 6,500 tons per year.
In addition, the nitrogen fertilizer plant is moving forward
with an approximately $120 million fertilizer plant
expansion, of which approximately $11 million was incurred
as of March 31, 2008. It is estimated that this expansion
will increase the nitrogen fertilizer plants capacity to
upgrade ammonia into premium-priced UAN by approximately 50%.
Management currently expects to complete this expansion in July
2010.
Experienced Management Team.
In
conjunction with the acquisition of our business in June 2005 by
funds affiliated with Goldman, Sachs & Co. and
Kelso & Company, L.P., or the Goldman Sachs Funds and
the Kelso Funds, a new senior management team was formed that
combined selected members of existing management with
experienced new members. Our senior management team averages
over 28 years of refining and fertilizer industry
experience and, in coordination with our broader management
team, has increased our operating income and stockholder value
since June 2005.
Mr. John J. Lipinski, our Chief Executive Officer, has over
36 years of experience in the refining and chemicals
industries, and prior to joining us in connection with the
acquisition of Coffeyville Resources in June 2005, was in charge
of a 550,000 bpd refining system and a multi-plant
fertilizer system. Mr. Stanley A. Riemann, our Chief
Operating Officer, has over 34 years of experience, and
prior to joining us in March 2004, was in charge of one of the
largest fertilizer manufacturing systems in the United States.
Mr. James T. Rens, our Chief Financial Officer, has over
19 years of experience in the energy and fertilizer
industries, and prior to joining us in March 2004, was the chief
financial officer of two fertilizer manufacturing companies.
Our Business
Strategy
The primary business objectives for our refinery business are to
increase value for our stockholders and to maintain our position
as an independent refiner and marketer of refined fuels in our
markets by maximizing the throughput and efficiency of our
petroleum refining assets. In addition, managements
business objectives on behalf of the Partnership are to increase
value for our stockholders and maximize the production and
efficiency of the nitrogen fertilizer facilities. We intend to
accomplish these objectives through the following strategies:
Pursuing Organic Expansion
Opportunities.
We continually evaluate
opportunities to expand our existing asset base and consider
capital projects that accentuate our core competitiveness in
petroleum refining. We are also evaluating projects that will
improve our ability to process heavy crude oil feedstocks and to
increase our overall operating flexibility with respect to crude
oil slates. In addition, management also continually evaluates
capital projects that are intended to enhance the
Partnerships competitiveness in nitrogen fertilizer
manufacturing.
Increasing the Profitability of Our Existing
Assets.
We strive to improve our operating
efficiency and to reduce our costs by controlling our cost
structure. We intend to make investments to improve the
efficiency of our operations and pursue cost saving initiatives.
We have recently completed the greenfield construction of a new
continuous catalytic reformer. This project is expected to
increase the profitability of our petroleum business through
increased refined product yields and the elimination of
scheduled downtime associated with the reformer that was
replaced. In addition, this project reduces the dependence of
our refinery on hydrogen supplied by the fertilizer facility,
thereby
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allowing the nitrogen fertilizer business to generate higher
margins by using the hydrogen to produce ammonia and UAN. The
nitrogen fertilizer business expects, over time, to convert 100%
of its production to higher-margin UAN.
Seeking Strategic Acquisitions.
We
intend to consider strategic acquisitions within the energy
industry that are beneficial to our shareholders. We will seek
acquisition opportunities in our existing areas of operation
that have the potential for operational efficiencies. We may
also examine opportunities in the energy industry outside of our
existing areas of operation and in new geographic regions. In
addition, working on behalf of the Partnership, management may
pursue strategic and accretive acquisitions within the
fertilizer industry, including opportunities in different
geographic regions. We have no agreements or understandings with
respect to any acquisitions at the present time.
Pursuing Opportunities to Maximize the Value of the
Nitrogen Fertilizer Business.
Our management,
acting on behalf of the Partnership, will continually evaluate
opportunities that are intended to enable the Partnership to
grow its distributable cash flow. Managements strategies
specifically related to the growth opportunities of the
Partnership include the following:
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Expanding UAN Production.
The nitrogen
fertilizer business is moving forward with an approximately
$120 million nitrogen fertilizer plant expansion, of which
approximately $11 million was incurred as of March 31,
2008. This expansion is expected to permit the nitrogen
fertilizer business to increase its UAN production and to result
in its UAN manufacturing facility consuming substantially all of
its net ammonia production. This should increase the nitrogen
fertilizer plants margins because UAN has historically
been a higher margin product than ammonia. The UAN expansion is
expected to be complete in July 2010 and it is estimated that it
will result in an approximately 50% increase in the nitrogen
fertilizer business annual UAN production. The company
has also begun to acquire or lease offsite UAN storage
facilities and continues to expand this program.
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Executing Several Efficiency-Based and Other
Projects.
The nitrogen fertilizer business is
currently engaged in several efficiency-based and other projects
in order to reduce overall operating costs, incrementally
increase its ammonia production and utilize byproducts to
generate revenue. For example, by redesigning the system that
segregates carbon dioxide, or
CO
2
,
during the gasification process, the nitrogen fertilizer
business estimates that it will be able to produce approximately
25 tons per day of incremental ammonia, worth approximately
$6 million per year at current market prices. The nitrogen
fertilizer business estimates that this project will cost
approximately $7 million (of which none has yet been incurred)
and will be completed in 2010.
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Evaluating Construction of a Third Gasifier Unit and a New
Ammonia Unit and UAN Unit at the Nitrogen Fertilizer
Plant.
The nitrogen fertilizer business has
engaged a major engineering firm to help it evaluate the
construction and operation of an additional gasifier unit to
produce a synthesis gas from pet coke. It is expected that the
addition of a third gasifier unit, together with additional
ammonia and UAN units, to the nitrogen fertilizer business
operations could result, on a long-term basis, in an increase in
UAN production of approximately 75,000 tons per month. This
project is in its earliest stages of review and is still subject
to numerous levels of internal analysis.
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Other opportunities our management may consider on behalf of the
Partnership in the event that its managing general partner
proceeds with an initial offering include acquiring certain of
our petroleum business ancillary assets and providing
incremental pipeline transportation and storage infrastructure
services to our petroleum business. There are currently no
agreements or understandings in place with respect to any such
acquisitions or opportunities, and there can be no assurance
that the Partnership would be able to operate any of these
assets or businesses profitably.
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Our
History
Our business was founded in 1906 by The National Refining
Company, which at the time was the largest independent oil
refiner in the United States. In 1944 the Coffeyville refinery
was purchased by the Cooperative Refinery Association, a
subsidiary of a parent company that in 1966 renamed itself
Farmland Industries, Inc. Our refinery assets and the nitrogen
fertilizer plant were operated as a small component of Farmland
Industries, Inc., an agricultural cooperative, until
March 3, 2004. Farmland filed for bankruptcy protection on
May 31, 2002.
Coffeyville Resources, LLC, a subsidiary of Coffeyville Group
Holdings, LLC, won the bankruptcy court auction for
Farmlands petroleum business and a nitrogen fertilizer
plant and completed the purchase of these assets on
March 3, 2004. On October 8, 2004, Coffeyville Group
Holdings, LLC, through two of its wholly owned subsidiaries,
Coffeyville Refining & Marketing, Inc. and Coffeyville
Nitrogen Fertilizers, Inc., acquired an interest in Judith
Leiber business, a designer handbag business, through an
investment in CLJV Holdings, LLC (CLJV), a joint venture with
The Leiber Group, Inc., whose majority stockholder was also the
majority stockholder of Coffeyville Group Holdings, LLC. On
June 23, 2005, the entire interest in the Judith Leiber
business held by CLJV was returned to The Leiber Group, Inc. in
exchange for all of its ownership interest in CLJV, resulting in
a complete separation of the Immediate Predecessor and the
Judith Leiber business.
On June 24, 2005, pursuant to a stock purchase agreement
dated May 15, 2005, Coffeyville Acquisition LLC, which was
formed in Delaware on May 13, 2005, acquired all of the
subsidiaries of Coffeyville Group Holdings, LLC. With the
exception of crude oil, heating oil and gasoline option
agreements entered into with J. Aron as of May 16, 2005,
Coffeyville Acquisition LLC had no operations from its inception
until the acquisition on June 24, 2005.
We were formed in Delaware in September 2006 as a wholly owned
subsidiary of Coffeyville Acquisition LLC in order to complete
the initial public offering of the businesses acquired by
Coffeyville Acquisition, LLC from Coffeyville Group Holdings
LLC. We completed our initial public offering on
October 26, 2007. At that time, we transferred the nitrogen
fertilizer business to CVR Partners, LP, a limited partnership
we formed in June 2007. As consideration for the transfer, we
received 30,303,000 special GP units and 30,333 special LP units
in the Partnership, and the Partnerships managing general
partner, which at that time was our indirect wholly-owned
subsidiary, received the managing general partner interest and
the IDRs. Immediately prior to the consummation of our initial
public offering, we sold the managing general partner, together
with the IDRs, to Coffeyville Acquisition III LLC, an
entity owned by the Goldman Sachs Funds, the Kelso Funds and
certain members of CVR Energys senior management team, for
its fair market value on the date of sale.
Petroleum
Business
Asset
Description
We operate one of the seven refineries located within the
mid-continent region (Kansas, Oklahoma, Missouri, Nebraska and
Iowa). The Companys complex cracking and coking
medium-sour oil refinery has a maximum capacity of
123,500 bpd of petroleum products, which accounts for
approximately 17% of the regions output. The facility is
situated on approximately 440 acres in southeastern Kansas,
approximately 100 miles from Cushing, Oklahoma, a major
crude oil trading and storage hub.
The refinery is a complex facility. Complexity is a measure of a
refinerys ability to process lower quality crude in an
economic manner. It is also a measure of a refinerys
ability to convert lower cost, more abundant heavier and sour
crudes into greater volumes of higher valued refined products
such as gasoline and distillate, thereby providing a competitive
advantage over less complex refineries. We have a modified
Solomon complexity score of approximately 12.1, up from 10.0 in
June 2005. Modified Solomon complexity is a standard
industry measure of a refinerys ability to process less-
149
expensive feedstock, such as heavier and higher-sulfur content
crude oils, into value-added products. Modified Solomon
complexity is the weighted average of the Solomon complexity
factors for each operating unit multiplied by the throughput of
each refinery unit, divided by the crude capacity of the
refinery. For the year ended December 31, 2007, our
refinerys product yield included gasoline (mainly regular
unleaded) (45%), diesel fuel (mainly ultra low sulfur diesel)
(42%), and coke and other refined products such as NGL (propane,
butane), slurry, reformer feeds, sulfur, gas oil and produced
fuel (13%).
The refinery consists of two crude units and two vacuum units. A
vacuum unit is a secondary unit which processes crude oil by
separating product from the crude unit according to boiling
point under high heat and low pressure to recover various
hydrocarbons. The availability of more than one crude and vacuum
unit creates redundancy in the refinery system and enables us to
continue to run the refinery even if one of these units were to
shut down for scheduled or unscheduled plant maintenance and
upgrades. However, the maximum combined capacity of the crude
units is limited by the overall downstream capacity of the
vacuum units and other units.
Our petroleum business also includes the following auxiliary
operating assets:
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Crude Oil Gathering System.
We own and
operate a 25,000 bpd capacity crude oil gathering system
serving central Kansas, northern Oklahoma and southwestern
Nebraska. The system has field offices in Bartlesville, Oklahoma
and Plainville and Winfield, Kansas. The system is comprised of
over 300 miles of feeder and trunk pipelines, 43 trucks,
and associated storage facilities for gathering light, sweet
Kansas, Nebraska and Oklahoma crude oils purchased from
independent crude producers. We also lease a section of a
pipeline from Magellan Pipeline Company, L.P.
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Phillipsburg Terminal.
We own storage
and terminalling facilities for asphalt and refined fuels at
Phillipsburg, Kansas. Our asphalt storage and terminalling
facilities are used to receive, store and redeliver asphalt for
another oil company for a fee pursuant to an asphalt services
agreement. We also collect fees for refined products we store
for another oil company.
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Pipelines.
We own a 145,000 bpd
proprietary pipeline system that transports crude oil from
Caney, Kansas to our refinery. Crude oils sourced outside of our
proprietary gathering system are delivered by common carrier
pipelines into various terminals in Cushing, Oklahoma, where
they are blended and then delivered to Caney, Kansas via a
pipeline owned by Plains All American L.P. We also own
associated crude oil storage tanks with a capacity of
approximately 1.2 million barrels located outside our
refinery.
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Rack Marketing Division.
We own a rack
marketing division which supplies product through tanker trucks
directly to customers located in close geographic proximity to
our refinery and Phillipsburg terminal and to customers at
throughput terminals on Magellan Midstream Partners L.P.s
refined products distribution systems.
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Feedstocks
Supply
Our refinery has the capability to process blends of a variety
of crudes ranging from heavy sour to light sweet crudes.
Currently, our refinery processes crude from a broad array of
sources. We purchase foreign crudes from Latin America, South
America, West Africa, the Middle East, the North Sea and Canada.
We purchase domestic crudes from Kansas, Oklahoma, Nebraska,
Texas, and offshore deepwater Gulf of Mexico production. While
crude oil has historically constituted over 85% of our feedstock
inputs during the last five years, other feedstock inputs
include isobutane, normal butane, natural gas, alky feed, gas
oil and vacuum tower bottoms.
Crude is supplied to our refinery through our wholly owned
gathering system and by pipeline. Our crude gathering system was
expanded in 2006 and currently supplies in excess of
21,000 bpd of crude to the refinery (approximately 20% of
total supply). Locally produced crudes are delivered to the
150
refinery at a discount to WTI and are of similar quality to WTI.
These lighter sweet crudes allow us to blend higher percentages
of low cost crudes such as heavy sour Canadian while maintaining
our target medium sour blend with an API gravity of
28-36
degrees and 0.9-1.2% sulfur. Crude oils sourced outside of our
proprietary gathering system are delivered to Cushing, Oklahoma
by various pipelines including Seaway, Basin and Spearhead and
subsequently to Coffeyville via Plains pipeline and our own
145,000 bpd proprietary pipeline system.
For the year ended December 31, 2007, our crude oil supply
blend was comprised of approximately 65% light sweet crude oil,
12% heavy sour crude oil and 23% medium/light sour crude oil.
The light sweet crude oil includes our locally gathered crude
oil. For the three months ended March 31, 2008, our crude
oil supply blend was comprised of approximately 68% of light
sweet crude oil, 14% heavy sour crude oil and 18% medium/light
sour crude oil.
We purchase most of our crude oil requirements outside of our
proprietary gathering system under a credit intermediation
agreement with J. Aron. The credit intermediation agreement
helps us reduce our inventory position and mitigate crude
pricing risk. Once we identify cargos of crude oil and pricing
terms that meet our requirements, we notify J. Aron which then
provides, for a fee, credit, transportation and other logistical
services for delivery of the crude to the crude oil tank farm.
Generally, we select crude oil approximately 30 to 45 days
in advance of the time the related refined products are to be
marketed, except for Canadian and West African crude purchases
which require an additional 30 days of lead time due to
transit considerations.
Distribution,
Sales and Marketing
We focus our petroleum products marketing efforts in the central
mid-continent and Rocky Mountain areas because of their relative
proximity to our oil refinery and their pipeline access. Since
June 2005, we have significantly expanded our rack sales. Rack
sales are sales made using tanker trucks via either a
proprietary or third party terminal facility designed for truck
loading. In the year ended December 31, 2007, approximately
23% of the refinerys products were sold through the rack
system directly to retail and wholesale customers while the
remaining 77% was sold through pipelines via bulk spot and term
contracts. We make bulk sales (sales through third party
pipelines) into the mid-continent markets via Magellan and into
Colorado and other destinations utilizing the product pipeline
networks owned by Magellan, Enterprise and NuStar.
We are able to distribute gasoline, diesel fuel, and natural gas
liquids produced at the refinery either into the Magellan or
Enterprise pipelines and further on through NuStar and other
Magellan systems or via the trucking system. The
Magellan #2 and #3 pipelines (with capacity of
81,000 bpd and 32,000 bpd, respectively) are connected
directly to the refinery and transport products to Kansas City
and other northern cities. The NuStar and Magellan (Mountain)
pipelines are accessible via the Enterprise outbound line (with
capacity of 12,000 bpd) or through the Magellan system at
El Dorado, Kansas. Our fuels loading rack at our refinery has a
maximum delivery capability of 40,000 bpd of finished
gasoline and diesel fuels.
151
The following map depicts part of the Magellan pipeline, which
the oil refinery uses for the majority of its distribution.
Source: Magellan Midstream Partners, L.P.
Customers
Customers for our petroleum products include other refiners,
convenience store companies, railroads and farm cooperatives. We
have bulk term contracts in place with many of these customers,
which typically extend from a few months to one year in length.
For the year ended December 31, 2007, QuikTrip Corporation
accounted for 11.6% of our petroleum business sales and 64.3% of
our petroleum sales were made to our 10 largest customers. For
the three months ended March 31, 2008, QuikTrip Corporation
accounted for 14.8% of our petroleum business sales and 66.1% of
our petroleum sales were made to our 10 largest customers.
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Competition
Our oil refinery in Coffeyville, Kansas ranks second in
processing capacity and fifth in refinery complexity, among the
seven mid-continent fuels refineries. The following table
presents certain information about us and the six other major
mid-continent fuel oil refineries with which we compete:
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Crude Capacity
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Solomon
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(Barrels per
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Complexity
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Company
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Location
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Calendar Day)
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Index
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ConocoPhillips
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Ponca City, OK
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187,000
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13.7
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CVR Energy
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Coffeyville, KS
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115,000
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12.1
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Frontier Oil
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El Dorado, KS
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110,000
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13.0
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Valero
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Ardmore, OK
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91,500
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11.2
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NCRA
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McPherson, KS
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82,700
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13.1
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Sinclair
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Tulsa, OK
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70,000
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6.2
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Gary Williams Energy
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Wynnewood, OK
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52,500
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8.5
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Mid-continent Total:
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708,700
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Source: Oil and Gas Journal. A Sunoco refinery located
in Tulsa, Oklahoma was excluded from this table because it is
not a stand-alone fuels refinery. The Solomon Complexity Index
of each of these facilities has been calculated based on data
from the Oil and Gas Journal together with Company estimates and
assumptions.
We compete with our competitors primarily on the basis of price,
reliability of supply, availability of multiple grades of
products and location. The principal competitive factors
affecting our refining operations are costs of crude oil and
other feedstock costs, refinery complexity (a measure of a
refinerys ability to convert lower cost heavy and sour
crudes into greater volumes of higher valued refined products
such as gasoline), refinery efficiency, refinery product mix and
product distribution and transportation costs. The location of
our refinery provides us with a reliable supply of crude oil and
a transportation cost advantage over our competitors.
Our competitors include trading companies such as SemFuel, L.P.,
Western Petroleum, Center Oil, Tauber Oil Company, Morgan
Stanley and others. In addition to competing refineries located
in the mid-continent United States, our oil refinery also
competes with other refineries located outside the region that
are linked to the mid-continent market through an extensive
product pipeline system. These competitors include refineries
located near the U.S. Gulf Coast and the Texas Panhandle
region.
Our refinery competition also includes branded, integrated and
independent oil refining companies such as BP, Shell,
ConocoPhillips, Valero, Sunoco and Citgo, whose strengths
include their size and access to capital. Their branded stations
give them a stable outlet for refinery production although the
branded strategy requires more working capital and a much more
expensive marketing organization.
Seasonality
Our petroleum business experiences seasonal effects as demand
for gasoline products is generally higher during the summer
months than during the winter months due to seasonal increases
in highway traffic and road construction work. Demand for diesel
fuel during the winter months also decreases due to agricultural
work declines during the winter months. As a result, our results
of operations for the first and fourth calendar quarters are
generally lower than for those for the second and third calendar
quarters. In addition, unseasonably cool weather in the summer
months
and/or
unseasonably warm weather in the winter months in the markets in
which we sell our petroleum products can vary demand for
gasoline and diesel fuel.
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Nitrogen
Fertilizer Business
The nitrogen fertilizer business operates the only nitrogen
fertilizer plant in North America that utilizes a coke
gasification process to generate hydrogen feedstock that is
further converted to ammonia for the production of nitrogen
fertilizers. The nitrogen fertilizer business is also moving
forward with an $120 million fertilizer plant expansion, of
which approximately $11 million was incurred as of
March 31, 2008, which we estimate could increase the
facilitys capacity to upgrade ammonia into premium priced
UAN by 50% and which we expect to be completed in June 2010.
The facility uses a gasification process licensed from an
affiliate of The General Electric Company, or General Electric,
to convert pet coke to high purity hydrogen for subsequent
conversion to ammonia. It uses between 975 to 1,075 tons per day
of pet coke from the refinery and another 260 to 310 tons per
day from unaffiliated, third-party sources such as other
Midwestern refineries or pet coke brokers and converts it all to
approximately 1,200 tons per day of ammonia. The fertilizer
plant has demonstrated consistent levels of production at levels
close to full capacity and has the following advantages compared
to competing natural gas-based facilities:
Significantly Lower Cost Position.
Our
nitrogen fertilizer plants pet coke gasification process
uses approximately 1% of the natural gas used by other
nitrogen-based fertilizer facilities that are heavily dependent
upon natural gas and are thus heavily impacted by natural gas
price swings. Because the nitrogen fertilizer plant uses pet
coke, we have a significant cost advantage over other North
American natural gas-based fertilizer producers. This cost
advantage is sustainable at natural gas prices as low as $2.50
per MMBtu. Natural gas sold at an average price of $7.12 per
MMBtu in the United States in 2007. Average yearly natural gas
prices have exceeded $2.50 per MMBtu since 2000, although
average prices were lower in prior years. See Industry
Overview Fertilizer Pricing Trends. Natural
gas prices are cyclical and volatile and may decline at any
time. See Risk Factors Risks Related to the
Nitrogen Fertilizer Business Natural gas prices
affect the price of the nitrogen fertilizers that the nitrogen
fertilizer business sells. Any decline in natural gas prices
could have a material adverse effect on our results of
operations, financial condition and the ability of the nitrogen
fertilizer business to make cash distributions. CVR
Energys adjacent refinery has supplied on average more
than 75% of our pet coke needs during the last four years.
Strategic Location with Transportation
Advantage.
The nitrogen fertilizer business
believes that selling products to customers in close proximity
to the UAN plant and reducing transportation costs are keys to
maintaining its profitability. Due to the plants favorable
location relative to end users and high product demand relative
to production volume all of the product shipments are targeted
to freight advantaged destinations located in the U.S. farm
belt. The available ammonia production at the nitrogen
fertilizer plant is small and easily sold into truck and rail
delivery points. The products leave the plant either in trucks
for direct shipment to customers or in railcars for principally
Union Pacific Railroad destinations. The nitrogen fertilizer
business does not incur any intermediate transfer, storage,
barge freight or pipeline freight charges. Consequently, because
these costs are not incurred, we estimate that the plant enjoys
a distribution cost advantage over those competitors who are
U.S. Gulf Coast ammonia and UAN importers, assuming in each
case freight rates and pipeline tariffs for U.S. Gulf Coast
importers as recently in effect.
On-Stream Factor.
The on-stream factor
is a measure of how long the units comprising our nitrogen
fertilizer facility have been operational over a given period.
We expect that efficiency of the nitrogen fertilizer plant will
continue to improve with operator training, replacement of
unreliable equipment, and reduced dependence on contract
maintenance.
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Year Ended December 31,
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2003
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2004(1)
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2005
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2006(1)
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2007(1)
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Gasifier
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90.1
|
%
|
|
|
92.4
|
%
|
|
|
98.1
|
%
|
|
|
92.5
|
%
|
|
|
90.0
|
%
|
Ammonia
|
|
|
89.6
|
%
|
|
|
79.9
|
%
|
|
|
96.7
|
%
|
|
|
89.3
|
%
|
|
|
87.7
|
%
|
UAN
|
|
|
81.6
|
%
|
|
|
83.3
|
%
|
|
|
94.3
|
%
|
|
|
88.9
|
%
|
|
|
78.7
|
%
|
154
|
|
|
(1)
|
|
On-stream factor is the total number of hours operated divided
by the total number of hours in the reporting period. Excluding
the impact of turnarounds at the nitrogen fertilizer facility in
the third quarter of 2004 and 2006, (i) the on-stream
factors in 2004 would have been 95.6% for gasifier, 83.1% for
ammonia and 86.7% for UAN, and (ii) the on-stream factors
for the year ended December 31, 2006 would have been 97.1%
for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the
impact of the flood during the weekend of June 30, 2007,
the on-stream factors for the year ended December 31, 2007
would have been 94.6% for gasifier, 92.4% for ammonia and 83.9%
for UAN.
|
Raw Material
Supply
The nitrogen fertilizer facilitys primary input is pet
coke. During the past four years, more than 75% of the nitrogen
fertilizer facilitys pet coke requirements on average were
supplied by our adjacent oil refinery. Historically the nitrogen
fertilizer business has obtained the remainder of its pet coke
from third parties such as other midwestern refineries or pet
coke brokers at spot prices. If necessary, the gasifier can also
operate on low grade coal as an alternative, which provides an
additional raw material source. There are significant supplies
of low grade coal within a
60-mile
radius of the nitrogen fertilizer plant.
Pet coke is produced as a by-product of our refinerys
coker unit process, which is one step in refining crude oil into
gasoline, diesel and jet fuel. In order to refine heavy or sour
crude oil, which is lower in cost and more prevalent than higher
quality crude, refiners use coker units, which help to reduce
the sulfur content in fuels refined from heavy or sour crude
oil. In North America, the shift from refining dwindling
reserves of sweet crude oil to more readily available heavy and
sour crude (which can be obtained from, among other places, the
Canadian oil sands) will result in increased pet coke
production. With $26.6 billion in coker unit projects
planned at North American refineries as of November 2007, pet
coke production is expected to increase significantly in the
future.
The nitrogen fertilizer plant is located in Coffeyville, Kansas,
which is part of the Midwest coke market. The Midwest coke
market is not subject to the same level of pet coke price
variability as is the U.S. Gulf Coast coke market, due
mainly to more stable transportation costs. Transportation costs
have gone up substantially in both the Atlantic and Pacific
sectors. Given the fact that the majority of the nitrogen
fertilizer business suppliers are located in the Midwest,
its geographic location gives it (and its similarly located
competitors) a significant freight cost advantage over its
U.S. Gulf Coast market competitors. The Midwest Green Coke
(Chicago Area, FOB Source) annual average price over the last
three years has ranged from $24.50 per ton to $27.00. The
U.S. Gulf Coast market annual average price during the same
period has ranged from $21.29 per ton to $49.83. Furthermore,
Sinclair Tulsa Refining, located in Oklahoma, has announced a
coker expansion project, and Frontier in El Dorado, Kansas has a
coker expansion project under construction. These new refineries
should help to further stabilize the Midwest coke market.
The Linde Group owns, operates, and maintains the air separation
plant that provides contract volumes of oxygen, nitrogen, and
compressed dry air to the gasifier for a monthly fee. The
nitrogen fertilizer business provides and pays for all utilities
required for operation of the air separation plant. The air
separation plant has not experienced any long-term operating
problems. The nitrogen fertilizer plant is covered for business
interruption insurance for up to $25.0 million in case of
any interruption in the supply of oxygen from Linde from a
covered peril. The agreement with Linde expires in 2020. The
agreement also provides that if our requirements for liquid or
gaseous oxygen, liquid or gaseous nitrogen or clean dry air
exceed specified instantaneous flow rates by at least 10%, we
can solicit bids from Linde and third parties to supply our
incremental product needs. We are required to provide notice to
Linde of the approximate quantity of excess product that we will
need and the approximate date by which we will need it; we and
Linde will then jointly develop a request for proposal for
soliciting bids from third parties and Linde. The bidding
procedures may be limited under specified circumstances.
155
The nitrogen fertilizer business imports
start-up
steam for the fertilizer plant from our adjacent oil refinery,
and then exports steam back to the oil refinery once all of its
units are in service. Monthly charges and credits are booked
with steam valued at the gas price for the month. We have
entered into a feedstock and shared services agreement with the
Partnership which regulates, among other things, the import and
export of
start-up
steam between the refinery and the nitrogen fertilizer plant.
Production
Process
The nitrogen fertilizer plant was built in 2000 with two
separate gasifiers to provide reliability. It uses a
gasification process licensed from General Electric to convert
pet coke into high purity hydrogen for subsequent conversion
into ammonia. Following a turnaround completed in the second
quarter of 2006, the plant is capable of processing
approximately 1,300 tons per day of pet coke from the oil
refinery and third-party sources and converting it into
approximately 1,200 tons per day of ammonia. A majority of the
ammonia is converted to approximately 2,000 tons per day of UAN.
Typically 0.41 tons of ammonia are required to produce one ton
of UAN.
Pet coke is first ground and blended with water and a fluxant (a
mixture of fly ash and sand) to form a slurry that is then
pumped into the partial oxidation gasifier. The slurry is then
contacted with oxygen from an air separation unit, or ASU.
Partial oxidation reactions take place and the synthesis gas, or
syngas, consisting predominantly of hydrogen and carbon
monoxide, is formed. The mineral residue from the slurry is a
molten slag (a glasslike substance containing the metal
impurities originally present in coke) and flows along with the
syngas into a quench chamber. The syngas and slag are rapidly
cooled and the syngas is separated from the slag.
Slag becomes a by-product of the process. The syngas is scrubbed
and saturated with moisture. The syngas next flows through a
shift unit where the carbon monoxide in the syngas is reacted
with the moisture to form hydrogen and carbon dioxide. The heat
from this reaction generates saturated steam. This steam is
combined with steam produced in the ammonia unit and the excess
steam not consumed by the process is sent to the adjacent oil
refinery.
After additional heat recovery, the high-pressure syngas is
cooled and processed in the acid gas removal, or AGR, unit. The
syngas is then fed to a pressure swing absorption, or PSA, unit,
where the remaining impurities are extracted. The PSA unit
reduces residual carbon monoxide and carbon dioxide levels to
trace levels, and the moisture-free, high-purity hydrogen is
sent directly to the ammonia synthesis loop.
The hydrogen is reacted with nitrogen from the ASU in the
ammonia unit to form the ammonia product. A portion of the
ammonia is converted to UAN.
156
The following is an illustrative Nitrogen Fertilizer Plant
Process Flow Chart:
The nitrogen fertilizer business schedules and provides routine
maintenance to its critical equipment using its own maintenance
technicians. Pursuant to a Technical Services Agreement with
General Electric, which licenses the gasification technology to
the nitrogen fertilizer business, General Electric experts
provide technical advice and technological updates from their
ongoing research as well as other licensees operating
experiences.
The pet coke gasification process is licensed from General
Electric pursuant to a license agreement that was fully paid up
as of June 1, 2007. The license grants the nitrogen
fertilizer business perpetual rights to use the pet coke
gasification process on specified terms and conditions. The
license is important because it allows the nitrogen fertilizer
facility to operate at a low cost compared to facilities which
rely on natural gas.
Distribution,
Sales and Marketing
The primary geographic markets for the fertilizer products are
Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas.
Ammonia products are marketed to industrial and agricultural
customers and UAN products are marketed to agricultural
customers. The direct application agricultural demand from the
nitrogen fertilizer plant occurs in three main use periods. The
summer wheat pre-plant occurs in August and September. The fall
pre-plant occurs in late October and November. The highest level
of ammonia demand is traditionally observed in the spring
pre-plant period, from March through May. There are also small
fill volumes that move in the off-season to fill the available
storage at the dealer level.
Ammonia and UAN are distributed by truck or by railcar. If
delivered by truck, products are sold on a
freight-on-board
basis, and freight is normally arranged by the customer. The
nitrogen fertilizer business also owns and leases a fleet of
railcars. It also negotiates with distributors that have their
own leased railcars to utilize these assets to deliver products.
The nitrogen fertilizer business owns all of the truck and rail
loading equipment at its facility. It operates two truck loading
and eight rail loading racks for each of ammonia and UAN.
The nitrogen fertilizer business markets agricultural products
to destinations that produce the best margins for the business.
These markets are primarily located on the Union Pacific
railroad or destinations which can be supplied by truck. By
securing this business directly, the nitrogen fertilizer
business reduces its dependence on distributors serving the same
customer base, which enables it to capture a larger margin and
allows it to better control its product distribution. Most of
the agricultural sales are made on a competitive spot basis. The
nitrogen fertilizer business also offers products on a
157
prepay basis for in-season demand. The heavy in-season demand
periods are spring and fall in the corn belt and summer in the
wheat belt. The corn belt is the primary corn producing region
of the United States, which includes Illinois, Indiana, Iowa,
Minnesota, Missouri, Nebraska, Ohio and Wisconsin. The wheat
belt is the primary wheat producing region of the United States,
which includes Kansas, North Dakota, Oklahoma, South Dakota and
Texas. Some of the industrial sales are spot sales, but most are
on annual or multiyear contracts. Industrial demand for ammonia
provides consistent sales and allows the nitrogen fertilizer
business to better manage inventory control and generate
consistent cash flow.
Customers
The nitrogen fertilizer business sells ammonia to agricultural
and industrial customers. It sells approximately 80% of the
ammonia it produces to agricultural customers, in the
mid-continent area between North Texas and Canada, and
approximately 20% to industrial customers. Agricultural
customers include distributors such as MFA, United Suppliers,
Inc., Brandt Consolidated Inc., ConAgra Fertilizer, Interchem,
and CHS, Inc. Industrial customers include Tessenderlo Kerley,
Inc. and National Cooperative Refinery Association. The nitrogen
fertilizer business sells UAN products to retailers and
distributors. Given the nature of its business, and consistent
with industry practice, the nitrogen fertilizer business does
not have long-term minimum purchase contracts with any of its
customers.
For the years ended December 31, 2005, 2006 and 2007 and
the three months ended March 31, 2008, the top five ammonia
customers in the aggregate represented 55.2%, 51.9%, 62.1% and
68.4% of the nitrogen fertilizer business ammonia sales,
respectively, and the top five UAN customers in the aggregate
represented 43.1%, 30.0%, 38.7% and 42.4% of its UAN sales,
respectively. During the year ended December 31, 2005,
Brandt Consolidated Inc. and MFA accounted for 23.3% and 13.6%
of the nitrogen fertilizer business ammonia sales,
respectively, and CHS Inc. and ConAgra Fertilizer accounted for
14.7% and 12.7% of its UAN sales, respectively. During the year
ended December 31, 2006, Brandt Consolidated Inc. and MFA
accounted for 22.2% and 13.1% of the nitrogen fertilizer
business ammonia sales, respectively, and ConAgra
Fertilizer and CHS Inc. accounted for 8.4% and 6.8% of its UAN
sales, respectively. During the year ended December 31,
2007, Brandt Consolidated Inc., MFA and ConAgra Fertilizer
accounted for 17.4%, 15.0% and 14.4% of the nitrogen fertilizer
business ammonia sales, respectively, and ConAgra
Fertilizer accounted for 18.7% of its UAN sales. During the
three months ended March 31, 2008, Brandt Consolidated Inc.
and National Cooperative Refinery Association accounted for
32.3% and 9.6% of the nitrogen fertilizer business ammonia
sales, respectively, and ConAgra Fertilizer accounted for 11.1%
of its UAN sales.
Competition
Competition in the nitrogen fertilizer industry is dominated by
price considerations. However, during the spring and fall
application seasons, farming activities intensify and delivery
capacity is a significant competitive factor. The nitrogen
fertilizer plant maintains a large fleet of rail cars and
seasonally adjusts inventory to enhance its manufacturing and
distribution operations.
Domestic competition, mainly from regional cooperatives and
integrated multinational fertilizer companies, is intense due to
customers sophisticated buying tendencies and production
strategies that focus on cost and service. Also, foreign
competition exists from producers of fertilizer products
manufactured in countries with lower cost natural gas supplies.
In certain cases, foreign producers of fertilizer who export to
the United States may be subsidized by their respective
governments. The nitrogen fertilizer business major
competitors include Koch Nitrogen, PCS, Terra and CF Industries,
all of which produce more UAN than the nitrogen fertilizer
business does.
The nitrogen fertilizer plants main competition in ammonia
marketing are Kochs plants at Beatrice, Nebraska, Dodge
City, Kansas and Enid, Oklahoma, as well as Terras plants
in Verdigris and Woodward, Oklahoma and Port Neal, Iowa.
158
Based on Blue Johnson data regarding total U.S. demand for
UAN and ammonia, we estimate that the nitrogen fertilizer
plants UAN production in 2007 represented approximately
4.5% of the total U.S. demand and that the net ammonia
produced and marketed at Coffeyville represents less than 1% of
the total U.S. demand.
Seasonality
Because the nitrogen fertilizer business primarily sells
agricultural commodity products, its business is exposed to
seasonal fluctuations in demand for nitrogen fertilizer products
in the agricultural industry. As a result, the nitrogen
fertilizer business typically generates greater net sales and
operating income in the spring. In addition, the demand for
fertilizers is affected by the aggregate crop planting decisions
and fertilizer application rate decisions of individual farmers
who make planting decisions based largely on the prospective
profitability of a harvest. The specific varieties and amounts
of fertilizer they apply depend on factors like crop prices,
farmers current liquidity, soil conditions, weather
patterns and the types of crops planted.
Environmental
Matters
The petroleum and nitrogen fertilizer businesses are subject to
extensive and frequently changing federal, state and local laws
and regulations relating to the protection of the environment.
These laws, their underlying regulatory requirements and the
enforcement thereof impact our petroleum and nitrogen fertilizer
businesses by imposing:
|
|
|
|
|
restrictions on operations
and/or
the
need to install enhanced or additional controls;
|
|
|
|
the need to obtain and comply with permits, licenses and
authorizations;
|
|
|
|
liability for the investigation and remediation of contaminated
soil and groundwater at current and former facilities and
off-site waste disposal locations; and
|
|
|
|
specifications for the products manufactured and marketed by our
petroleum and nitrogen fertilizer businesses, primarily
gasoline, diesel fuel, UAN and ammonia.
|
The petroleum refining industry is subject to frequent public
and governmental scrutiny of its environmental compliance. The
laws and regulations to which we are subject are often evolving
and many of them have become more stringent or have become
subject to more stringent interpretation or enforcement by
federal and state agencies. The ultimate impact of complying
with existing laws and regulations is not always clearly known
or determinable due in part to the fact that our operations may
change over time and certain implementing regulations for laws
such as the Resource Conservation and Recovery Act (the
RCRA), the federal Clean Water Act and the federal
Clean Air Act have not yet been finalized, are frequently
undergoing governmental or judicial review or are being revised.
These regulations and other new hazardous or solid waste, air or
water quality standards or stricter fuel regulations could
result in increased capital, operating and compliance costs.
The principal environmental risks associated with our petroleum
and nitrogen fertilizer businesses are air emissions, releases
of hazardous substances into the environment, and the treatment
and discharge of wastewater. The legislative and regulatory
programs that affect these areas are outlined below. For a
discussion of the environmental impact of the 2007 flood and
crude oil discharge, see Flood and Crude Oil
Discharge Crude Oil Discharge and
Flood and Crude Oil Discharge EPA
Administrative Order on Consent.
The Federal
Clean Air Act
The federal Clean Air Act and its implementing regulations as
well as the corresponding state laws and regulations that
regulate emissions of pollutants into the air affect our
petroleum operations and the nitrogen fertilizer business both
directly and indirectly. Direct impacts may occur through
federal and state air permitting requirements
and/or
emission control requirements relating to specific
159
air pollutants. The federal Clean Air Act indirectly affects our
petroleum operations and the nitrogen fertilizer business by
extensively regulating the air emissions of sulfur dioxide
(SO
2
),
volatile organic compounds, nitrogen oxides and other compounds
including those emitted by mobile sources, which are direct or
indirect users of our products.
Some or all of the standards promulgated pursuant to the federal
Clean Air Act, or any future promulgations of standards, may
require the installation of controls or changes to our petroleum
operations or the nitrogen fertilizer facilities in order to
comply. If new controls or changes to operations are needed, the
costs could be significant. These new requirements, other
requirements of the federal Clean Air Act, or other presently
existing or future environmental regulations could cause us to
expend substantial amounts to comply
and/or
permit our refinery to produce products that meet applicable
requirements.
Air Emissions.
The regulation of air
emissions under the federal Clean Air Act requires us to obtain
various construction and operating permits and to incur capital
expenditures for the installation of certain air pollution
control devices at our refinery. Various regulations specific
to, or that directly impact, our industry have been implemented,
including regulations that seek to reduce emissions from
refineries flare systems, sulfur plants, large heaters and
boilers, fugitive emission sources and wastewater treatment
systems. Some of the applicable programs are the various general
and specific source standards under the National Emission
Standard for Hazardous Air Pollutants (NESHAP), New
Source Performance Standards and New Source Review. We have
incurred, and expect to continue to incur, substantial capital
expenditures to maintain compliance with these and other air
emission regulations.
In March 2004, we entered into a Consent Decree with the
U.S. Environmental Protection Agency (the EPA)
and the Kansas Department of Health and Environment (the
KDHE) to resolve air compliance concerns raised by
the EPA and KDHE related to Farmlands prior operation of
our oil refinery. Under the Consent Decree, we agreed to install
controls on certain process equipment and make certain
operational changes at our refinery. As a result of our
agreement to install certain controls and implement certain
operational changes, the EPA and KDHE agreed not to seek civil
penalties, and provided a release from liability for
Farmlands alleged noncompliance with the issues addressed
by the Consent Decree. Pursuant to the Consent Decree, in the
short term, we have increased the use of catalyst additives to
the fluid catalytic cracking unit at the facility to reduce
emissions of
SO
2
.
We began adding catalyst to reduce oxides of nitrogen
(NOx) in 2008. In the long term, we will install
controls to minimize both
SO
2
and NOx emissions, which under terms of the Consent Decree
require that final controls be in place by January 1, 2011.
In addition, pursuant to the Consent Decree, we assumed certain
cleanup obligations at the Coffeyville refinery and the
Phillipsburg terminal. We agreed to retrofit certain heaters at
the refinery with Ultra Low NOx burners. All heater retrofits
have been completed and we are currently verifying that the
heaters meet the Ultra Low NOx standards required by the Consent
Decree. The Ultra Low NOx heater technology is in widespread use
throughout the industry. There are other permitting, monitoring,
record-keeping and reporting requirements associated with the
Consent Decree. The overall cost of complying with the Consent
Decree is expected to be approximately $41 million, of
which approximately $35 million is expected to be capital
expenditures and which does not include the cleanup obligations.
Over the course of the last several years, the EPA has embarked
on a National Petroleum Refining Initiative alleging
industry-wide noncompliance with four marquee
issues: New Source Review, flaring, Leak Detection and Repair,
and Benzene Waste Operations NESHAP. The Petroleum Refining
Initiative has resulted in many refiners entering into consent
decrees imposing civil penalties and requiring substantial
expenditures for additional or enhanced pollution control. The
EPA has indicated that it will seek all refiners to enter into
global settlements pertaining to all
marquee issues. Our current Consent Decree covers
some, but not all, of the marquee issues. To the
extent that we were to agree to enter into a global
settlement, we believe our incremental capital exposure
would be limited primarily to the retrofit and replacement of
certain existing heaters and boilers over a five to seven year
timeframe. We also would incur additional operating expenses to
enhance our
160
flaring and leak detection and control programs. In addition,
consistent with other refiners that have entered into
global settlements, we may be required to pay a
civil penalty.
Title V Air Permitting.
The
petroleum refinery is a major source of air
emissions under the Title V permitting program of the
federal Clean Air Act. A final Class I (major source)
operating permit was issued for our oil refinery in August 2006.
We are currently in the process of amending the Title V
permit to include the recently approved expansion project permit
and the continuous catalytic reformer permit. The nitrogen
fertilizer plant has amended its Title V permit application
to contain all terms and conditions imposed under its new
Prevention of Significant Deterioration (PSD) permit
and all other air permits
and/or
approvals in place. We do not anticipate significant cost or
difficulty in obtaining the Title V operating air permit
for the nitrogen fertilizer plant. We believe that we hold all
material air permits required to operate the Phillipsburg
Terminal and our crude oil transportation companys
facilities.
Release
Reporting
The release of hazardous substances or extremely hazardous
substances into the environment is subject to release reporting
of threshold quantities under federal and state environmental
laws. Our petroleum operations and the nitrogen fertilizer
business periodically experience releases of hazardous
substances and extremely hazardous substances that could cause
our petroleum business
and/or
the
nitrogen fertilizer business to become the subject of a
government enforcement action or third-party claims.
The nitrogen fertilizer facility experienced an ammonia release
as a result of a malfunction in August 2007 and reported the
excess ammonia emissions to the EPA and KDHE. The EPA has
investigated the release and has requested additional data. Our
incident investigation related to the release indicates that the
malfunction could not have been reasonably anticipated or
avoided and we have forwarded our results to the EPA.
As a result of an inspection by OSHA following the August 2007
ammonia release OSHA issued citations against both the nitrogen
fertilizer facility and the refinery seeking penalties totaling
$163,000. We have agreed to settle all allegations as a result
of this incident with payment of a $163,000 penalty and review
and, if necessary, implement improvements in general health and
safety programs at each facility, which may include integrating
the plant alarm and notification systems.
Fuel
Regulations
Tier II, Low Sulfur Fuels.
In February
2000, the EPA promulgated the Tier II Motor Vehicle
Emission Standards Final Rule for all passenger vehicles,
establishing standards for sulfur content in gasoline. These
regulations mandate that the sulfur content of gasoline at any
refinery shall not exceed 30 ppm during any calendar year
beginning January 1, 2006. Such compliant gasoline is
referred to as Ultra Low Sulfur Gasoline (ULSG).
Phase-in of these requirements began during 2004. In addition,
in January 2001, the EPA promulgated its on-road diesel
regulations, which required a 97% reduction in the sulfur
content of diesel sold for highway use by June 1, 2006,
with full compliance by January 1, 2010. The EPA adopted a
rule for off-road diesel in May 2004. The off-road diesel
regulations will generally require a 97% reduction in the sulfur
content of diesel sold for off-road use by June 1, 2010.
Such compliant diesel is referred to as Ultra Low Sulfur Diesel
(ULSD). Our production of ULSG and ULSD made us
eligible for significant tax benefits in 2007, and we expect to
be eligible for significant tax benefits in 2008 as well.
Modifications have been and will continue to be required at our
refinery as a result of the Tier II gasoline and low sulfur
diesel standards. In February 2004 the EPA granted us approval
under a hardship waiver that defers meeting final
low sulfur Tier II gasoline standards until January 1,
2011 and deferred meeting low sulfur highway diesel requirements
until January 1, 2007. We completed the construction and
startup phase of our Ultra Low Sulfur Diesel
Hydrodesulfurization unit in late 2006 in accordance with the
conditions of the hardship waiver. We are currently
continuing our phased
161
construction and startup of projects related to meeting our
compliance date with ULSG standards and may agree to meet these
standards one year early as described below. Compliance with the
Tier II gasoline and on-road diesel standards required us
to spend approximately $133 million during 2006 and
approximately $103 million during 2007, and we estimate
that compliance will require us to spend approximately
$68 million between 2008 and 2010. Changes in equipment or
construction costs could require significantly greater
expenditures.
In 2007, as a result of the flood, our refinery exceeded the
required average gasoline sulfur standard mandated by the
hardship waiver. We are re-negotiating provisions of the
hardship waiver and have agreed in principal to meet the final
low sulfur Tier II gasoline standards by January 1,
2010 (one year earlier than required under the hardship waiver)
in consideration for the EPAs agreement not to seek a
penalty for the 2007 sulfur exceedance and higher gasoline
sulfur limits for 2008 and 2009.
Greenhouse Gas
Emissions
The United States Congress has considered various proposals to
reduce greenhouse gas emissions, but none have become law, and
presently, there are no federal mandatory greenhouse gas
emissions requirements. While it is probable that Congress will
adopt some form of federal mandatory greenhouse gas emission
reductions legislation in the future, the timing and specific
requirements of any such legislation are uncertain at this time.
In the absence of existing federal regulations, a number of
states have adopted regional greenhouse gas initiatives to
reduce
CO
2
and other greenhouse gas emissions. In 2007, a group of Midwest
states, including Kansas (where our refinery and the nitrogen
fertilizer facility are located), formed the Midwestern
Greenhouse Gas Accord, which calls for the development of a
cap-and-trade
system to control greenhouse gas emissions and for the inventory
of such emissions. However, the individual states that have
signed on to the accord must adopt laws or regulations
implementing the trading scheme before it becomes effective, and
the timing and specific requirements of any such laws or
regulations in Kansas are uncertain at this time.
In 2007, the U.S. Supreme Court decided that
CO
2
is an air pollutant under the federal Clean Air Act for the
purposes of vehicle emissions. Similar lawsuits have been filed
seeking to require the EPA to regulate
CO
2
emissions from stationary sources, such as our refinery and the
fertilizer plant, under the federal Clean Air Act. Our refinery
and the nitrogen fertilizer plant produce significant amounts of
CO
2
that are vented into the atmosphere. If the EPA regulates
CO
2
emissions from facilities such as ours, we may have to apply for
additional permits, install additional controls to reduce
CO
2
emissions or take other as yet unknown steps to comply with
these potential regulations. For example, we may have to
purchase
CO
2
emission reduction credits to reduce our current emissions of
CO
2
or to offset increases in
CO
2
emissions associated with expansions of our operations.
Compliance with any future legislation or regulation of
greenhouse gas emissions, if it occurs, may result in increased
compliance and operating costs and may have a material adverse
effect on our results of operations, financial condition, and
the ability of the nitrogen fertilizer business to make
distributions. In anticipation of the potential legislation or
regulation of greenhouse gas emissions, the nitrogen fertilizer
business is looking into initiatives to reduce greenhouse gas
emissions, particularly
CO
2
,
and is working with a company involved in
CO
2
capture and storage systems to try to develop plans whereby the
nitrogen fertilizer business may, in the future, either sell
approximately 850,000 tons per year of high purity
CO
2
produced by the nitrogen fertilizer plant to oil and gas
exploration and production companies to enhance oil recovery or
pursue an economic means of geologically sequestering such
CO
2
.
This project is currently in development, but, if completed, is
expected to include either the direct sale of
CO
2
or the sale of verified emission reduction credits should the
credits accrete value in the future due to the implementation of
mandatory emissions caps for
CO
2
.
162
The Clean
Water Act
The federal Clean Water Act of 1972 affects our petroleum
operations and the nitrogen fertilizer business by regulating
the treatment of wastewater and imposing restrictions on
effluent discharges into, or impacting, navigable water. Regular
monitoring, reporting requirements and performance standards are
preconditions for the issuance and renewal of permits governing
the discharge of pollutants into water. Our petroleum business
maintains numerous discharge permits as required under the
National Pollutant Discharge Elimination System program of the
federal Clean Water Act and has implemented internal programs to
oversee our compliance efforts. Our nitrogen fertilizer facility
operates under pretreatment requirements and has a permit to
discharge our process wastewater to the local publicly owned
treatment works.
All of our facilities are subject to Spill Prevention, Control
and Countermeasures (SPCC) requirements under the
Clean Water Act. In 2004, certain requirements of the rule were
extended, and additional modifications are expected. When the
modifications to the SPCC rule become final, we may be required
to make capital expenditures in order to comply with the
modified rule; however, we do not anticipate that any such costs
will be significant.
In addition, we are regulated under the Oil Pollution Act of
1990 (the Oil Pollution Act). Among other
requirements, the Oil Pollution Act requires the owner or
operator of a tank vessel or facility to maintain an emergency
oil response plan to respond to releases of oil or hazardous
substances. We have developed and implemented such a plan for
each of our facilities covered by the Oil Pollution Act. Also,
in case of such releases, the Oil Pollution Act requires
responsible parties to pay the resulting removal costs and
damages, provides for substantial civil penalties, and
authorizes the imposition of criminal and civil sanctions for
violations. States where we have operations have laws similar to
the Oil Pollution Act.
Wastewater Management.
We have a
wastewater treatment plant at our refinery permitted to handle
an average flow of 2.2 million gallons per day. The
facility uses a complete mix activated sludge (CMAS)
system with three CMAS basins. The plant operates pursuant to a
KDHE permit. We are also implementing a comprehensive spill
response plan in accordance with the EPA rules and guidance.
Ongoing fuels terminal and asphalt plant operations at
Phillipsburg generate only limited wastewater flows (e.g.,
boiler blowdown, asphalt loading rack condensate, groundwater
treatment). These flows are handled in a wastewater treatment
plant that includes a primary clarifier, aerated secondary
clarifier, and a final clarifier to a lagoon system. The plant
operates pursuant to a KDHE Water Pollution Control Permit. To
control facility runoff, management implements a comprehensive
Spill Response Plan. Phillipsburg also has a timely and current
application on file with the KDHE for a separate storm water
control permit.
Resource
Conservation and Recovery Act (RCRA)
Our operations are subject to the RCRA requirements for the
generation, treatment, storage and disposal of hazardous wastes.
When feasible, RCRA materials are recycled instead of being
disposed of
on-site
or
off-site. RCRA establishes standards for the management of solid
and hazardous wastes. Besides governing current waste disposal
practices, RCRA also addresses the environmental effects of
certain past waste disposal operations, the recycling of wastes
and the regulation of underground storage tanks containing
regulated substances.
Waste Management.
There are two closed
hazardous waste units at the refinery and eight other hazardous
waste units in the process of being closed pending state agency
approval. In addition, one closed interim status hazardous waste
landfarm located at the Phillipsburg terminal is under long-term
post closure care.
We have set aside approximately $3.2 million in financial
assurance for closure/post-closure care for hazardous waste
management units at the Phillipsburg terminal and the
Coffeyville refinery.
163
Impacts of Past Manufacturing.
We are
subject to a 1994 EPA administrative order related to
investigation of possible past releases of hazardous materials
to the environment at the refinery. In accordance with the
order, we have documented existing soil and ground water
conditions, which require investigation or remediation projects.
The Phillipsburg terminal is subject to a 1996 EPA
administrative order related to investigation of possible past
releases of hazardous materials to the environment at the
Phillipsburg terminal, which operated as a refinery until 1991.
The Consent Decree that we signed with the EPA and KDHE requires
us to complete all activities in accordance with federal and
state rules and to maintain financial assurance (e.g., a bond or
letter of credit) for the costs of doing so. See
Financial Assurance, below.
The anticipated remediation costs through 2011 were estimated,
as of March 31, 2008, to be as follows (in millions):
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Total
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Site
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Total O&M
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Estimated
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Investigation
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Costs
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Costs
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Facility
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Costs
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Capital Costs
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Through 2011
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Through 2011
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Coffeyville Oil Refinery
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$
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0.3
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$
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$
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1.1
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$
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1.4
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Phillipsburg Terminal
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0.3
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1.9
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2.2
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Total Estimated Costs
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$
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0.6
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$
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$
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3.0
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$
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3.6
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These estimates are based on current information and could go up
or down as additional information becomes available through our
ongoing remediation and investigation activities. At this point,
we have estimated that, over ten years starting in 2008, we will
spend between $5.8 million and $6.3 million to remedy
impacts from past manufacturing activity at the refinery and to
address existing soil and groundwater contamination at the
Phillipsburg terminal. It is possible that additional costs will
be required after this ten year period.
Financial Assurance.
We were required
in the Consent Decree to establish $15.0 million in
financial assurance to cover the projected cleanup costs under
the 1994 and 1996 EPA administrative orders described above, in
the event we failed to fulfill our
clean-up
obligations. In accordance with the Consent Decree, this
financial assurance is partially secured by a bond posted by
Original Predecessor, Farmland. We are replacing the financial
assurance currently provided by Farmland on a quarterly basis
and, so far, have replaced approximately $4.5 million. At
this point, it is not clear what the amount of financial
assurance will be when replaced. Although it may be significant,
we do not expect it will be more than $15.0 million.
Environmental Insurance.
We have
entered into environmental insurance policies as part of our
overall risk management strategy. Our primary pollution legal
liability policy provides us with an aggregate limit of
$25.0 million subject to a $5.0 million self-insured
retention. This policy covers cleanup costs resulting from
pre-existing or new pollution conditions and bodily injury and
property damage resulting from pollution conditions. It also
includes a $25.0 million business interruption sub-limit
subject to a
45-day
waiting period. Our excess pollution legal liability policies
provide us with up to an additional $50.0 million of
aggregate limit. The excess pollution legal liability policies
may not provide coverage until the $25.0 million of
underlying limit available in the primary pollution legal
liability policy has been exhausted. We also have a financial
assurance policy linked to our pollution legal liability policy
that provides a $4.0 million limit per pollution incident
and an $8.0 million aggregate policy limit related
specifically to closed RCRA units at the refinery and the
Phillipsburg terminal. Each of these policies contains
substantial exclusions; as such, there can be no assurance that
we will have coverage for all or any particular liabilities. For
a discussion of our insurance policies that relate to coverage
for the 2007 flood and crude oil discharge, see
Flood and Crude Oil Discharge
Insurance.
164
Environmental
Remediation
Under the Comprehensive Environmental Response, Compensation,
and Liability Act (CERCLA), RCRA, and related state
laws, certain persons may be liable for the release or
threatened release of hazardous substances. These persons
include the current owner or operator of property where a
release or threatened release occurred, any persons who owned or
operated the property when the release occurred, and any persons
who disposed of, or arranged for the transportation or disposal
of, hazardous substances at a contaminated property. Liability
under CERCLA is strict, retroactive and joint and several, so
that any responsible party may be held liable for the entire
cost of investigating and remediating the release of hazardous
substances. The liability of a party is determined by the cost
of investigation and remediation, the portion and toxicity of
the hazardous substance(s) the party contributed, the number of
solvent potentially responsible parties, and other factors.
As is the case with all companies engaged in similar industries,
we face potential exposure from future claims and lawsuits
involving environmental matters, including soil and water
contamination, personal injury or property damage allegedly
caused by hazardous substances that we, or potentially Farmland,
manufactured, handled, used, stored, transported, spilled,
released or disposed of. We cannot assure you that we will not
become involved in future proceedings related to our release of
hazardous or extremely hazardous substances or that, if we were
held responsible for damages in any existing or future
proceedings, such costs would be covered by insurance or would
not be material.
Safety, Health
and Security Matters
We operate a comprehensive safety, health and security program,
involving the active participation of employees at all levels of
the organization. We measure our success in the health and
safety area primarily through the use of injury frequency rates
administered by OSHA. In 2007, our oil refinery experienced a
75% reduction in injury frequency rates and the nitrogen
fertilizer plant experienced a 81% reduction in such rate as
compared to the average of the previous three years. The
recordable injury rate reflects the number of recordable
incidents (injuries as defined by OSHA) per 200,000 hours
worked, and for the year ended December 31, 2007, we had a
recordable injury rate of 0.50 in our petroleum business and
0.93 in the nitrogen fertilizer business, which did not have a
single lost-time accident. Our recordable injury rate for all
business units was 0.28 for the year ended December 31,
2007, and 0.57 for the quarter ended March 31, 2008. In
2006, our refinery achieved one year worked without a lost-time
accident, which based on available records, had never been
achieved in the 100 year history of the facility. In March
2007 our petroleum business achieved a milestone after operating
for 1,000,000 consecutive man hours without a lost-time
accident. For the year ended December 31, 2007, our
nitrogen fertilizer business did not have a single lost-time
accident. Despite our efforts to achieve excellence in our
safety and health performance, we cannot assure you that there
will not be accidents resulting in injuries or even fatalities.
We have implemented a new incident investigation program that is
intended to improve the safety for our employees by identifying
the root cause of accidents and potential accidents and by
correcting conditions that could cause or contribute to
accidents or injuries. We routinely audit our programs and
consider improvements in our management systems.
Process Safety Management.
We maintain
a Process Safety Management (PSM) program. This
program is designed to address all facets associated with OSHA
guidelines for developing and maintaining a PSM program. We will
continue to audit our programs and consider improvements in our
management systems and equipment.
We have evaluated and continue to implement improvements at our
refinerys process units, process pumping and piping
systems and emergency isolation valves for control of process
flows. We currently estimate the costs for implementing any
recommended improvements to be between $7 million and
$9 million over a period of four years. These improvements,
if warranted, would reduce
165
the risk of releases, spills, discharges, leaks, accidents,
fires or other events and minimize the potential effects
thereof. We are currently completing the
start-up
of
the final additions of a new $27 million refinery flare
system that replaced any remaining atmospheric sumps in our
refinery. We have assessed the potential impacts on building
occupancy caused by the location and design of our refinery and
fertilizer plant control rooms and operator shelters. We have
relocated non-essential personnel and contractors away from the
process areas and are currently constructing and installing
permanent blast-proof operator control rooms and outside
shelters. We expect the costs to upgrade or relocate these areas
to be between $4 million and $6 million over the next
two to five years.
In 2007, OSHA began PSM inspections of all refineries under its
jurisdiction as part of its National Emphasis Program (the
NEP) following OSHAs investigation of PSM
issues relating to the multiple fatality explosion and fire at
the BP Texas City facility in 2005. Completed NEP inspections
have resulted in OSHA levying significant fines and penalties
against most of the refineries inspected to date. At this time,
our refinery has not been inspected in connection with
OSHAs NEP program. Although we believe that our PSM
program is in substantial compliance with OSHA PSM regulations,
an OSHA NEP inspection could result in the imposition of
significant fines and penalties as well as significant
additional capital expenditures related to PSM.
Emergency Planning and Response.
We
have an emergency response plan that describes the organization,
responsibilities and plans for responding to emergencies in the
facilities. This plan is communicated to local regulatory and
community groups. We have
on-site
warning siren systems and personal radios. We will continue to
audit our programs and consider improvements in our management
systems and equipment.
Security.
We have a comprehensive
security program to protect our refinery and the nitrogen
fertilizer facility from unauthorized entry and exit and
potential acts of terrorism. Recent changes in the
U.S. Department of Homeland Security rules and requirements
may require enhancements and improvements to our current program.
Community Advisory Panel.
We have
developed and continue to support ongoing discussions with the
community to share information about our operations and future
plans. Our community advisory panel includes wide representation
of residents, business owners and local elected representatives
for the city and county.
Employees
As of March 31, 2008, 455 employees were employed in
our petroleum business, 110 were employed by the nitrogen
fertilizer business and 49 employees were employed at our
offices in Sugar Land, Texas and Kansas City, Kansas.
We entered into collective bargaining agreements which, as of
March 31, 2008, covered approximately 42% of our employees
(all of whom work in our petroleum business) with the Metal
Trades Union and the United Steelworkers of America. The
collective bargaining agreements expire in March 2009. We
believe that our relationship with our employees is good.
Prior to the consummation of our initial public offering, we
entered into a services agreement with the Partnership and the
managing general partner of the Partnership pursuant to which we
agreed to provide certain management and other services to the
Partnership, the managing general partner of the Partnership,
and the nitrogen fertilizer business. The services we provide
under the agreement include the following services, among others:
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services by our employees as the Partnerships corporate
executive officers, including chief executive officer, chief
operating officer, chief financial officer, general counsel,
fertilizer general manager, and vice president for
environmental, health and safety, except that those who serve in
such capacities under the agreement serve the Partnership on a
shared, part-time basis only, unless we and the Partnership
agree otherwise;
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administrative and professional services, including legal,
accounting services, human resources, insurance, tax, credit,
finance, government affairs and regulatory affairs;
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management of the property of the Partnership and Coffeyville
Resources Nitrogen Fertilizers, LLC, a subsidiary of the
Partnership, in the ordinary course of business;
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recommendations on capital raising activities, including the
issuance of debt or equity securities, the entry into credit
facilities and other capital market transactions;
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managing or overseeing litigation and administrative or
regulatory proceedings, and establishing appropriate insurance
policies for the Partnership, and providing safety and
environmental advice;
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recommending the payment of distributions; and
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managing or providing advice for other projects as may be agreed
by us and the managing general partner of the Partnership from
time to time.
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Personnel performing the actual day-to-day business and
operations of the Partnership at the plant level are employed
directly by the Partnership and its subsidiaries, which bear all
personnel costs for these employees. We pay all compensation and
benefits for our executive officers, including executive
officers who perform services for the Partnership, and we are
reimbursed by the managing general partner of the Partnership
for a pro rata portion of such compensation and benefits based
on the percentage of time each officer works for the
Partnership. For more information on this services agreement,
see The Nitrogen Fertilizer Limited
Partnership Intercompany Agreements.
Properties
The following table contains certain information regarding our
principal properties
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Location
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Acres
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Own/Lease
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Use
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Coffeyville, KS
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440
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Own
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Oil refinery, fertilizer plant and office buildings
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Phillipsburg, KS
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200
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Own
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Terminal facility
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Montgomery County, KS (Coffeyville Station)
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20
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Own
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Crude oil storage
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Montgomery County, KS (Broome Station)
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20
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Own
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Crude oil storage
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Bartlesville, OK
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25
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Own
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Truck storage and office buildings
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Winfield, KS
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5
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Own
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Truck storage
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Cushing, OK
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185
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Own
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Crude oil storage
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Cowley County, KS (Hooser Station)
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80
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Own
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Crude oil storage
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Holdrege, NE
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7
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Own
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Crude oil storage
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Stockton, KS
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6
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Own
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Crude oil storage
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Sugar Land, TX
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22,000 (square feet)
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Lease
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Office space
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Kansas City, KS
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18,400 (square feet)
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Lease
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Office space
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Our executive offices are located at 2277 Plaza Drive in Sugar
Land, Texas. We lease approximately 22,000 square feet at
that location. Rent under the lease is currently approximately
$515,000 annually, plus operating expenses, increasing to
approximately $550,000 in 2009. The lease expires in 2011. Rent
under our lease for the Kansas City office space is
approximately $268,000 annually, plus a portion of operating
expenses and taxes. The lease expires in 2009. We expect that
our current owned and leased facilities will be sufficient for
our needs over the next twelve months.
167
In January 2008, we transferred ownership of certain parcels of
land, including land that the fertilizer plant is situated on,
to the Partnership so that the Partnership would be able to
operate the fertilizer plant on its own land. Additionally, in
October 2007, we entered into a new cross easement agreement
with the Partnership so that both we and the Partnership will be
able to access and utilize each others land in certain
circumstances in order to operate our respective businesses in a
manner to provide flexibility for both parties to develop their
respective properties, without depriving either party of the
benefits associated with the continuous reasonable use of the
other parties property. For more information on this
cross-easement agreement, see The Nitrogen Fertilizer
Limited Partnership Intercompany Agreements.
As of December 31, 2007, we had storage capacity for
769,000 barrels of gasoline, 1,068,000 barrels of
distillates, 928,000 barrels of intermediates and
3,364,000 barrels of crude oil. The crude oil storage
consisted of 674,000 barrels of refinery storage capacity,
520,000 barrels of field storage capacity and
2,170,000 barrels of storage at Cushing, Oklahoma.
Legal
Proceedings
We are, and will continue to be, subject to litigation from time
to time in the ordinary course of our business, including
matters such as those described above under
Environmental Matters. We are not party
to any pending legal proceedings that we believe will have a
material impact on our business, and there are no existing legal
proceedings where we believe that the reasonably possible loss
or range of loss is material.
168
FLOOD AND CRUDE
OIL DISCHARGE
Overview
During the weekend of June 30, 2007, torrential rains in
southeastern Kansas caused the Verdigris River to overflow its
banks and flood the city of Coffeyville. The river crested more
than ten feet above flood stage, setting a new record for the
river. Approximately 2,000 citizens and hundreds of homes
throughout the city of Coffeyville were affected. Our refinery
and the nitrogen fertilizer plant, both of which are located in
close proximity to the Verdigris River, were severely flooded
and were forced to conduct emergency shutdowns and evacuations.
The majority of the refinerys process units were under
four to six feet of water and portions of the refinerys
tank farms and wastewater treatment area were covered with eight
to ten feet of water. As a result, the refinery and nitrogen
fertilizer facilities sustained major damage and required
extensive repairs.
Property Damage
and Lost Earnings
The refinery sustained damage to a large number of pumps,
motors, tanks, control rooms and other buildings, electrical
equipment and electronic controls, and required significant
clean-up
in
the areas surrounding the water and wastewater treatment plants.
We hired nearly 1,000 extra contract workers to help repair and
replace damaged equipment. The refinery started operating its
reformer on August 6, 2007 and began to charge crude oil to
the facility on August 9, 2007. Substantially all of the
refinerys units were in operation by August 20, 2007.
The nitrogen fertilizer facility, situated on slightly higher
ground, sustained less damage than the refinery. Bringing the
nitrogen fertilizer plant back on line involved replacing or
repairing 30% of all electric drives, repairing 60% of the
plants motor control centers, refurbishing 100% of the
plants distributive control systems and programmable logic
controllers and repairing the main control room. The nitrogen
fertilizer facility initiated startup at its production facility
on July 13, 2007.
As of March 31, 2008, total third party costs to repair the
refinery and fertilizer facilities were approximately
$82.5 million and $4.0 million, respectively. In
addition, we currently estimate that approximately
$2.1 million in third party costs related to the repair of
flood damaged property will be recorded in future periods. We
are currently uncertain how much of these amounts we will be
able to recover through insurance. See
Insurance.
Crude Oil
Discharge
Because the Verdigris River rose so rapidly during the flood,
much faster than predicted, our employees had to shut down and
secure the refinery in six to seven hours, rather than the
24 hours typically needed for such an effort. Despite our
efforts to secure the refinery prior to its evacuation as a
result of the flood, we estimate that 1,919 barrels (80,600
gallons) of crude oil and 226 barrels of crude oil
fractions were discharged from our refinery into the Verdigris
River flood waters beginning on or about July 1, 2007. In
particular, crude oil and its fractions were released from
refinery storage tanks and the refinery sewer system. Crude oil
was carried by floodwaters downstream from our refinery and into
residential and commercial areas.
In response to the crude oil discharge, on July 1, 2007 we
established an incident command center and assembled a team of
environmental consultants and oil spill response contractors to
manage our response to the crude oil discharge.
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The OBRIENS Group managed the overall process,
including containment and recovery. The OBRIENS
Group is the largest provider of emergency preparedness and
crisis management services to the energy and internal shipping
industries.
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United States Environmental Services, LLC provided operations
support. This firm is a full-service environmental contracting
company specializing in environmental emergency response,
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in-plant industrial services, contaminated site remediation,
chemical/biological terrorism response, safety training and
industrial hygiene.
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The Center for Toxicology and Environmental Health oversaw
sampling, analysis and reporting for the operation. This firm
specializes in toxicology, risk assessment, industrial hygiene,
occupational health and response to emergencies involving the
release or threat of release of chemicals.
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On July 2, 2007, the EPA dispatched additional oil spill
response contractors to the site with the EPAs mobile
command post to monitor and coordinate pollution assessments
related to the flooding and the crude oil discharge.
Beginning on or about July 2, 2007, the EPAs oil
spill response contractors and we began jointly conducting daily
aerial overflights of the Coffeyville area and our refinery. On
or about July 2, 2007, (a) crude oil from the refinery
was observed to be in the flood waters surrounding the
above-ground storage tanks located at our refinery and
(b) oil was observed in the Verdigris River and in flood
waters that had inundated a portion of the city of Coffeyville.
Representatives from the KDHE and the Oklahoma Department of
Environmental Quality have also been heavily involved in the
response to the oil discharge.
EPA
Administrative Order on Consent
On July 10, 2007, we entered into an administrative order
on consent (the Consent Order) with the EPA. As set
forth in the Consent Order, the EPA concluded that the discharge
of oil from our refinery caused and may continue to cause an
imminent and substantial threat to the public health and
welfare. Pursuant to the Consent Order, we agreed to perform
specified remedial actions to respond to the discharge of crude
oil from our refinery.
Under the Consent Order, within 90 days after the
completion of such remedial action, we will submit to the EPA
for review and approval a final report summarizing the actions
taken to comply with the Consent Order. We have worked with the
EPA throughout the recovery process and we could be required to
reimburse the EPAs costs under the federal Oil Pollution
Act. Except as otherwise set forth in the Consent Order, the
Consent Order does not limit the EPAs rights to seek other
legal, equitable or administrative relief or action as it deems
appropriate and necessary against us or from requiring us to
perform additional activities pursuant to applicable law. Among
other things, the EPA reserved the right to assess
administrative penalties against us
and/or
to
seek civil penalties against us. In addition, the Consent Order
states that it is not a satisfaction of or discharge from any
claim or cause of action against us or any person for any
liability we or such person may have under statutes or the
common law, including any claims of the United States, for
penalties, costs and damages.
We expect to substantially complete remediation of the
contamination caused by the crude oil discharge by July 31,
2008 and anticipate minor remedial actions thereafter. Total net
costs recorded as of March 31, 2008 associated with
remediation efforts and third party property damage incurred by
the crude oil discharge are approximately $27.3 million.
This amount is net of anticipated insurance recoveries of
$21.4 million. In 2007, the Company received insurance
proceeds of $10.0 million under its property insurance
policy, $10.0 million under its environmental policies
related to recovery of certain costs associated with the crude
oil discharge and $1.5 million under its builders
risk policy. These amounts do not include potential fines or
penalties which may be imposed by regulatory authorities or
costs arising from potential natural resource damages claims
(for which we are unable to estimate a range of possible costs
at this time) or possible additional damages arising from
lawsuits related to the flood.
Property
Repurchase Program and Claims for Property Damage
On July 19, 2007 we commenced a program to purchase
approximately 330 homes and certain other properties in
connection with the flood and the crude oil discharge. We
offered to purchase the
170
property of approximately 330 residential landowners (with the
consent and cooperation of the city of Coffeyville) for 110% of
their pre-flood appraised value (to be established by appraisal
conducted without consideration of the flood), without release
or other waiver of any rights by the landowners, and without
deduction for the greater harm unquestionably caused to these
properties by the flood itself. As of March 31, 2008, 322
of these approximately 330 residential properties are under
contract. We estimate that this program will cost approximately
$17.5 million, excluding certain costs associated with
remediation.
In addition, in early July 2007 we opened a claims center in
Coffeyville and established a toll-free number to facilitate the
recording and processing of claims for compensation by those who
may have incurred property and other damages related to the oil
discharge. Staff assisted local residents in filing claims
related to the 2007 flood and crude oil discharge. We also
offered a toll-free number at the claims call center which was
answered 24 hours a day. Call center operators collected
property owners information and forwarded it to claims
adjustors. The claims adjustors contacted property owners to
schedule appointments. Operators also directed callers to local,
state and federal disaster response agencies for additional
assistance. As of the date of this prospectus, we have adjusted
most of these claims.
Litigation
As a result of the crude oil discharge, two putative class
action lawsuits (one federal and one state) were filed against
us
and/or
our subsidiaries in July 2007. The federal suit, Danny Dunham
vs. Coffeyville Resources, LLC, et al., was filed in the United
States District Court for the District of Kansas at Wichita
(case number
6:07-cv-01186-JTM-DWB).
The state suit, Western Plains Alliance, LLC and Western Plains
Operations, LLC v. Coffeyville Resources
Refining & Marketing, LLC, was filed in the District
Court of Montgomery County, Kansas (case number 07CV99I).
Plaintiffs complaint in the federal suit alleged that the
crude oil discharge resulted from our negligent operation of the
refinery and that class members suffered unspecified damages,
including damages to their personal and real property,
diminished property value, lost full use and enjoyment of their
property, lost or diminished business income and comprehensive
remediation costs. The federal suit sought recovery under the
federal Oil Pollution Act, Kansas statutory law imposing a duty
of compensation on a party that releases any material
detrimental to the soil or waters of Kansas, and the Kansas
common law of negligence, trespass and nuisance. This suit was
dismissed on November 6, 2007 for lack of subject matter
jurisdiction, and no appeal was taken.
The state suit sought class certification under applicable law.
The proposed class would have consisted of all persons and
entities who own or have owned real property within the
contaminated area, and all businesses
and/or
other
entities located within the contaminated area. The
Court conducted an evidentiary hearing on the issue of class
certification on October 24 and 25, 2007 and ruled against class
certification, leaving only the original two plaintiffs who have
agreed, subject to final documentation, to settle their claims
and dismiss the state lawsuit.
We recently received 16 notices of claims under the Oil
Pollution Act from private claimants in an aggregate amount of
approximately $4.4 million. No lawsuits related to these
claims have yet been filed.
Insurance
During and after the time of the 2007 flood and crude oil
discharge, Coffeyville Resources, LLC was insured under
insurance policies that were issued by a variety of insurers and
which covered various risks, such as damage to our property,
interruption of our business, environmental cleanup
171
costs, and potential liability to third parties for bodily
injury or property damage. These coverages include the following:
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Our primary property damage and business interruption insurance
program provided $300 million of coverage for flood-related
damage, subject to a deductible of $2.5 million per
occurrence and a
45-day
waiting period for business interruption loss. While we believe
that property insurance should cover substantially all of the
estimated total physical damage to our property, our insurance
carriers have cited potential coverage limitations and defenses
that might preclude such a result.
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Our builders risk policy provided coverage for property
damage to buildings in the course of construction. Flood-related
loss or damage was subject to a $100,000 deductible and
sub-limit of $50 million.
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Our environmental insurance coverage program provided coverage
for bodily injury, property damage, and cleanup costs resulting
from new pollution conditions. At the time of the flood, the
program included a primary policy with a $25.0 million
aggregate limit of liability. This policy was subject to a
$1 million self-insured retention. In addition, at the time
of the flood we had a $25.0 million excess policy that was
triggered by exhaustion of the primary policy. The excess policy
covered bodily injury and property damage resulting from new
pollution conditions, but did not cover cleanup costs.
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Our umbrella and excess liability coverage program provided
$100 million of coverage for claims in excess of
$5.0 million and other applicable insurance for third-party
claims of property damage and bodily injury arising out of the
sudden and accidental discharge of pollutants.
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Coffeyville Resources, LLC promptly notified its insurers of the
flood, the crude oil discharge, and related claims and lawsuits.
We are in the process of submitting our claims to, responding to
information requests from, and negotiating with the insurers
with respect to costs and damages related to the 2007 flood and
crude oil discharge. Our property insurers have raised a
question as to whether our facilities are principally located in
Zone A which is subject to a $10 million
insurance limit for flood or Zone B which is subject
to a $300 million insurance limit for flood. We have
reached agreement with 32.5% of our property insurers that our
facilities are principally located in Zone B. Our remaining
property insurers have not, at this time, agreed to this
position. In addition, our primary environmental liability
insurance carrier has asserted that our pollution liability
claims are for cleanup which is subject to a
$10 million sub-limit, rather than property
damage which is covered to the limits of the policy. The
excess carrier has reserved its rights under the primary
carriers position. While we will vigorously contest the
primary carriers position, we believe that if that
position were upheld, our umbrella and excess Comprehensive
General Liability policies would continue to provide coverage
for these claims. Although each insurer has reserved its rights
under various policy exclusions and limitations and has cited
potential coverage defenses, we are vigorously pursuing our
insurance recovery claims. We expect that ultimate recovery will
be subject to negotiation and, if negotiation is unsuccessful,
litigation.
Our insurance policies also provide coverage for interruption to
the business, including lost profits, and reimbursement for
other expenses and costs we have incurred relating to the
damages and losses suffered. This coverage, however, applies
only to losses incurred after a business interruption of
45 days. Because both the refinery and the nitrogen
fertilizer plant were restored to operation within this
45-day
period, a majority of the lost profits incurred because of the
flood are unlikely to be paid by our business interruption
insurance.
Financial Impact
on Our Results
Total gross costs recorded due to the flood and related crude
oil discharge that were included in our statement of operations
for the year ended December 31, 2007 were approximately
$146.8 million.
172
Of these gross costs, approximately $101.9 million were
associated with repair and other matters as a result of the
flood damage to our facilities. Included in this cost was
$7.6 million of depreciation for temporarily idled
facilities, $6.1 million of salaries, $2.2 million of
professional fees and $86.0 million for other repair and
related costs. There were approximately $44.9 million of
costs recorded for the year ended December 31, 2007 related
to the third party and property damage remediation as a result
of the crude oil discharge.
Total gross costs recorded due to the flood and related oil
discharge that were included in our statement of operations for
the three months ended March 31, 2008 were approximately
$7.6 million. Of these gross costs for the three month
period ended March 31, 2008, approximately
$3.8 million were associated with repair and other matters
as a result of the flood damage to our facilities. Included in
this cost was $0.3 million of professional fees and
$3.5 million for other repair and related costs. There were
also $3.8 million of costs recorded related to the third
party and property damage remediation as a result of the crude
oil discharge. We anticipate that approximately
$2.1 million in additional third party costs related to the
repair of flood damaged property will be recorded in future
periods.
As of March 31, 2008, we had received insurance proceeds of
$10.0 million under our property insurance policy, an
additional $10.0 million under our environmental policies
related to recovery of certain costs associated with the crude
oil discharge and $1.5 million under our Builders
Risk Insurance Policy. Although we believe that we will recover
substantial additional sums under our insurance policies, we are
not sure of the ultimate amount or timing of such recovery
because of the difficulty inherent in projecting the ultimate
resolution of our claims. The difference between what we
ultimately receive under our insurance policies compared to what
has been recorded in our financial statements could be material
to our financial statements. Ultimate recovery may require
litigation. We could recover substantially less than our full
claim.
Below is a summary of the gross cost and reconciliation of the
insurance receivable as of March 31, 2008 (in millions):
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Total Costs
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Total gross costs incurred
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$
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154.5
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Total insurance receivable
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(107.2
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)
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Net costs associated with the flood
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$
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47.3
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Receivable
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Reconciliation
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Total insurance receivable
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$
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107.2
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Less insurance proceeds received
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(21.5
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)
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Insurance receivable
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$
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85.7
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173
MANAGEMENT
Executive
Officers and Directors
The following table sets forth the names, positions and ages of
the executive officers and directors of CVR Energy. We also
indicate in the biographies below which executive officers and
directors of CVR Energy also hold similar positions with the
managing general partner of the Partnership. Senior management
of CVR Energy manages the Partnership pursuant to the services
agreement described under The Nitrogen Fertilizer Limited
Partnership Intercompany Agreements. All of
the named executive officers of CVR Energy listed below will
devote all of their time to CVR Energy and its wholly-owned
subsidiaries, except that certain of them will also devote a
portion of their time to the management of the Partnership.
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Name
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Age
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Position
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John J. Lipinski
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57
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Chairman of the Board of Directors, Chief Executive Officer and
President
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Stanley A. Riemann
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57
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Chief Operating Officer
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James T. Rens
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41
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Chief Financial Officer and Treasurer
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Edmund S. Gross
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57
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Senior Vice President, General Counsel and Secretary
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Daniel J. Daly, Jr.
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62
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Executive Vice President, Strategy
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Robert W. Haugen
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50
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Executive Vice President, Refining Operations
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Wyatt E. Jernigan
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56
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Executive Vice President, Crude Oil Acquisition and Petroleum
Marketing
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Kevan A. Vick
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54
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Executive Vice President and Fertilizer General Manager
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Christopher G. Swanberg
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50
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Vice President, Environmental, Health and Safety
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Scott L. Lebovitz
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32
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Director
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Regis B. Lippert
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68
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Director
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George E. Matelich
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52
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Director
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Steve A. Nordaker
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61
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Director
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Stanley de J. Osborne
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37
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Director
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Kenneth A. Pontarelli
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37
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Director
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Mark E. Tomkins
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52
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Director
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John J. Lipinski
has served as our chairman of the
board since October 2007, our chief executive officer and
president and a member of our board since September 2006, chief
executive officer and president of Coffeyville Acquisition LLC
since June 2005 and chief executive officer and president of
Coffeyville Acquisition II LLC and Coffeyville
Acquisition III LLC since October 2007. Since October 2007,
Mr. Lipinski has also served as the chief executive
officer, president and a director of the managing general
partner of the Partnership. Mr. Lipinski has over
35 years of experience in the petroleum refining and
nitrogen fertilizer industries. He began his career with Texaco
Inc. In 1985, Mr. Lipinski joined The Coastal Corporation,
eventually serving as Vice President of Refining with overall
responsibility for Coastal Corporations refining and
petrochemical operations. Upon the merger of Coastal with
El Paso Corporation in 2001, Mr. Lipinski was promoted
to Executive Vice President of Refining and Chemicals, where he
was responsible for all refining, petrochemical, nitrogen-based
chemical processing, and lubricant operations, as well as the
corporate engineering and construction group. Mr. Lipinski
left El Paso in 2002 and became an independent management
consultant. In 2004, he became a Managing Director and Partner
of Prudentia Energy, an advisory and management firm.
Mr. Lipinski graduated from Stevens Institute of Technology
with a Bachelor of Engineering (Chemical) and received a Juris
Doctor degree from Rutgers University School of Law.
Stanley A. Riemann
has served as chief operating
officer of our company since September 2006, chief operating
officer of Coffeyville Acquisition since June 2005, chief
operating officer of
174
Coffeyville Resources since February 2004 and chief operating
officer of Coffeyville Acquisition II and Coffeyville
Acquisition III since October 2007. Since October 2007
Mr. Riemann has also served as the chief operating officer
of the managing general partner of the Partnership. Prior to
joining our company in February 2004, Mr. Riemann held
various positions associated with the Crop Production and
Petroleum Energy Division of Farmland for over 29 years,
including, most recently, Executive Vice President of Farmland
and President of Farmlands Energy and Crop Nutrient
Division. In this capacity, he was directly responsible for
managing the petroleum refining operation and all domestic
fertilizer operations, which included the Trinidad and Tobago
nitrogen fertilizer operations. His leadership also extended to
managing Farmlands interests in SF Phosphates in Rock
Springs, Wyoming and Farmland Hydro, L.P., a phosphate
production operation in Florida, and managing all company-wide
transportation assets and services. Mr. Riemann served as a
board member and board chairman on several industry
organizations including the Phosphate Potash Institute, the
Florida Phosphate Council, and the International Fertilizer
Association. He currently serves on the board of The Fertilizer
Institute. Mr. Riemann received a B.S. from the University
of Nebraska and an M.B.A. from Rockhurst University.
James T. Rens
has served as chief financial
officer and treasurer of our company since September 2006, chief
financial officer and treasurer of Coffeyville Acquisition since
June 2005, chief financial officer and treasurer of Coffeyville
Resources since February 2004 and chief financial officer and
treasurer of Coffeyville Acquisition II and Coffeyville
Acquisition III since October 2007. Since October 2007,
Mr. Rens has also served as chief financial officer and
treasurer of the managing general partner of the Partnership.
Before joining our company, Mr. Rens was a consultant to
the Original Predecessors majority shareholder from
November 2003 to March 2004, assistant controller at Koch
Nitrogen Company from June 2003, which was when Koch acquired
the majority of Farmlands nitrogen fertilizer business, to
November 2003 and Director of Finance of Farmlands Crop
Production and Petroleum Divisions from January 2002 to June
2003. From May 1999 to January 2002, Mr. Rens was
controller and chief financial officer of Farmland Hydro L.P.
Mr. Rens has spent over 19 years in various accounting
and financial positions associated with the fertilizer and
energy industry. Mr. Rens received a B.S. degree in
accounting from Central Missouri State University.
Edmund S. Gross
has served as senior vice
president, general counsel and secretary of our company since
October 2007, senior vice president, general counsel and
secretary of Coffeyville Acquisition II and Coffeyville
Acquisition III since October 2007, vice president, general
counsel and secretary of our company since September 2006,
secretary of Coffeyville Acquisition since June 2005, and
general counsel and secretary of Coffeyville Resources since
July 2004. Since October 2007 Mr. Gross has also served as
the senior vice president, general counsel, and secretary of the
managing general partner of the Partnership. Prior to joining
Coffeyville Resources, Mr. Gross was Of Counsel at Stinson
Morrison Hecker LLP in Kansas City, Missouri from 2002 to 2004,
was Senior Corporate Counsel with Farmland Industries, Inc. from
1987 to 2002 and was an associate and later a partner at Weeks,
Thomas & Lysaught, a law firm in Kansas City, Kansas,
from 1980 to 1987. Mr. Gross received a B.A. in history
from Tulane University, a J.D. from the University of Kansas and
an M.B.A. from the University of Kansas.
Daniel J. Daly, Jr.
has been our executive
vice president, strategy since December 2007 and was our Senior
Vice President, Administration and Controls from September 2006
through December 2007 and our Vice President, Accounting and
Administration from June 2005 through August 2006. From December
2004 to June 2005 Mr. Daly was self-employed as a
consultant in mergers & acquisitions. From 1978 to
2001 Mr. Daly worked at Coastal Corporation, first as
Manager of Transportation and Supply Operations and then as
Controller, Refining Division and Vice President and Controller,
Refining and Marketing. Following the merger of Coastal with
El Paso in 2001, Mr. Daly served as Vice President and
Controller of Tosco Corporation from January 2001 to December
2001. Mr. Daly received a B.S. in commerce from
St. Louis University.
Robert W. Haugen
joined our business on
June 24, 2005 and has served as executive vice president,
refining operations at our company since September 2006 and as
executive vice
175
president engineering & construction at
Coffeyville Resources since June 24, 2005. Since October
2007 Mr. Haugen has also served as executive vice
president, refining operations at Coffeyville Acquisition and
Coffeyville Acquisition II. Mr. Haugen brings 25 years
of experience in the refining, petrochemical and nitrogen
fertilizer business to our company. Prior to joining us,
Mr. Haugen was a Managing Director and Partner of Prudentia
Energy, an advisory and management firm focused on
midstream/downstream energy sectors, from January 2004 to June
2005. On leave from Prudentia, he served as the Senior Oil
Consultant to the Iraqi Reconstruction Management Office for the
U.S. Department of State. Prior to joining Prudentia
Energy, Mr. Haugen served in numerous engineering,
operations, marketing and management positions at the Howell
Corporation and at the Coastal Corporation. Upon the merger of
Coastal and El Paso in 2001, Mr. Haugen was named Vice
President and General Manager for the Coastal Corpus Christi
Refinery, and later held the positions of Vice President of
Chemicals and Vice President of Engineering and Construction.
Mr. Haugen received a B.S. in chemical engineering from the
University of Texas.
Wyatt E. Jernigan
has served as executive vice
president, crude oil acquisition and petroleum marketing at our
company since September 2006 and as executive vice
president crude & feedstocks at
Coffeyville Resources since June 24, 2005. Since October
2007 Mr. Jernigan has also served as executive vice
president, crude oil acquisition and petroleum marketing at
Coffeyville Acquisition and Coffeyville Acquisition II.
Mr. Jernigan has 30 years of experience in the areas
of crude oil and petroleum products related to trading,
marketing, logistics and business development. Most recently,
Mr. Jernigan was Managing Director with Prudentia Energy,
an advisory and management firm focused on mid-stream/downstream
energy sectors, from January 2004 to June 2005. Most of his
career was spent with Coastal Corporation and El Paso,
where he held several positions in crude oil supply, petroleum
marketing and asset development, both domestic and
international. Following the merger between Coastal Corporation
and El Paso in 2001, Mr. Jernigan assumed the role of
Managing Director for Petroleum Markets Originations.
Mr. Jernigan attended Virginia Wesleyan College, majoring
in sociology, and has training in petroleum fundamentals from
the University of Texas.
Kevan A. Vick
has served as executive vice
president and fertilizer general manager at our company since
September 2006, senior vice president at Coffeyville Resources
Nitrogen Fertilizers since February 27, 2004 and executive
vice president and fertilizer general manager of Coffeyville
Acquisition III since October 2007. Since October 2007
Mr. Vick has also served as executive vice president and
fertilizer general manager of the managing general partner of
the Partnership. He has served on the board of directors of
Farmland MissChem Limited in Trinidad and SF Phosphates. He has
nearly 30 years of experience in the Farmland organization
and is an experienced executive in the nitrogen fertilizer
industry, known for both his technical expertise and his
in-depth knowledge of the commercial marketplace. Prior to
joining Coffeyville Resources, he was general manager of
nitrogen manufacturing at Farmland from January 2001 to February
2004. Mr. Vick received a B.S. in chemical engineering from
the University of Kansas and is a licensed professional engineer
in Kansas, Oklahoma and Iowa.
Christopher G. Swanberg
has served as vice
president, environmental, health and safety at our company since
September 2006, as vice president, environmental, health and
safety at Coffeyville Resources since June 2005 and as vice
president, environmental, health and safety at Coffeyville
Acquisition II and Coffeyville Acquisition III since
October 2007. Since October 2007 Mr. Swanberg has also
served as vice president, environmental, health and safety at
the managing general partner of the Partnership. He has served
in numerous management positions in the petroleum refining
industry such as Manager, Environmental Affairs for the refining
and marketing division of Atlantic Richfield Company (ARCO), and
Manager, Regulatory and Legislative Affairs for Lyondell-Citgo
Refining. Mr. Swanbergs experience includes technical
and management assignments in project, facility and corporate
staff positions in all environmental, safety and health areas.
Prior to joining Coffeyville Resources, he was vice president of
Sage Environmental Consulting, an environmental consulting firm
focused on petroleum refining and petrochemicals, from September
2002 to June 2005
176
and Senior HSE Advisor of Pilko & Associates, LP from
September 2000 to September 2002. Mr. Swanberg received a
B.S. in environmental engineering technology from Western
Kentucky University and an M.B.A. from the University of Tulsa.
Scott L. Lebovitz
has been a member of our board
since September 2006 and a member of the board of directors of
Coffeyville Acquisition II and Coffeyville
Acquisition III since October 2007. He was also a member of
the board of directors of Coffeyville Acquisition from June 2005
until October 2007. He has also been a member of the board of
directors of the managing general partner of the Partnership
since October 2007. Mr. Lebovitz is a managing director in
the Merchant Banking Division of Goldman, Sachs & Co.
Mr. Lebovitz joined Goldman, Sachs & Co. in 1997
and became a managing director in 2007. He is a director of
Energy Future Holdings Corp. and Village Voice Media Holdings,
LLC. He received his B.S. in commerce from the University of
Virginia.
Regis B. Lippert
has been a member of our board
since June 2007. He was also a member of the board of directors
of Coffeyville Acquisition from June 2007 until October 2007. He
is the founder, principal shareholder and a director of
INTERCAT, Inc., a specialty chemicals company which primarily
develops, manufactures, markets and sells specialty catalysts
used in petroleum refining. Mr. Lippert serves as president
and chief executive officer of INTERCAT, Inc. and its affiliate
companies and is a Managing Director of INTERCAT Europe B.V.
Mr. Lippert is also a director of Indo Cat Private Limited,
an Indian company which is part of a joint venture between
INTERCAT, Inc. and Indian Oil Corporation Limited. Prior to
founding INTERCAT, Mr. Lippert served from 1981 to 1985 as
President, Chief Executive Officer and a director of
Katalistiks, Inc., a manufacturer of fluid cracking catalysts
which ultimately became a subsidiary of Union Carbide
Corporation. From 1979 to 1981, Mr. Lippert was an
Executive Vice President with Catalysts Recovery, Inc. In this
capacity he was responsible for developing the joint venture
which ultimately formed Katalistiks. From 1963 to 1979,
Mr. Lippert was employed by Engelhard Minerals and Chemical
Co., where he attained the position of Director of Sales and
Marketing/Catalysts. Mr. Lippert attended Carnegie-Mellon
University where he studied metallurgy. He is a member of the
National Petroleum Refiners Association.
George E. Matelich
has been a member of our board
since September 2006, a member of the board of directors of
Coffeyville Acquisition since June 2005 and a member of the
board of directors of Coffeyville Acquisition III since
October 2007. He has also been a member of the board of
directors of the managing general partner of the Partnership
since October 2007. Mr. Matelich has been a managing
director of Kelso & Company since 1989.
Mr. Matelich has been affiliated with Kelso since 1985.
Mr. Matelich is a certified public accountant and holds a
Certificate in Management Consulting. Mr. Matelich received
a B.A. in business administration from the University of Puget
Sound and an M.B.A. from the Stanford Graduate School of
Business. He is a director of Global Geophysical Services, Inc.,
Shelter Bay Energy Inc. and Waste Services, Inc. He is also a
Trustee of the University of Puget Sound and serves on the
National Council of the American Prairie Foundation.
Steve A. Nordaker
has been a member of our board
since June 2008. He has served as senior vice president, finance
of Energy Capital Group Holdings LLC, a development company
dedicated to building, owning and operating gasification and
IGCC units for the refining, petrochemical and fertilizer
industries, since June 2004. Mr. Nordaker has also worked
as a financial consultant for various companies in the areas of
acquisitions, divestitures, restructuring and financial matters
since January 2002. From 1996 through 2001, he was a managing
director at J.P. Morgan Securities/JPMorgan Chase Bank in
the global chemicals group and global oil & gas group.
From 1992 to 1995, he was a managing director in the Chemical
Bank worldwide energy, refining and petrochemical group. From
1982 to 1992, Mr. Nordaker served in numerous banking
positions in the energy group at Texas Commerce Bank.
Mr. Nordaker was Manager of Projects for the Frantz
Company, an engineering consulting firm, from 1977 through 1982
and worked as a Chemical Engineer for UOP, Inc. from 1968
through 1977. Mr. Nordaker received a B.S. in chemical
engineering from South Dakota School of Mines and Technology and
an M.B.A. from the University of Houston.
177
Stanley de J. Osborne
has been a member of our
board since September 2006, a member of the board of directors
of Coffeyville Acquisition since June 2005 and a member of the
board of directors of Coffeyville Acquisition III since
October 2007. He has also been a member of the board of
directors of the managing general partner of the Partnership
since October 2007. Mr. Osborne was a Vice President of
Kelso & Company from 2004 through 2007 and has been a
managing director since 2007. Mr. Osborne has been
affiliated with Kelso since 1998. Prior to joining Kelso,
Mr. Osborne was an Associate at Summit Partners.
Previously, Mr. Osborne was an Associate in the Private
Equity Group and an Analyst in the Financial Institutions Group
at J.P. Morgan & Co. He received a B.A. in
Government from Dartmouth College. Mr. Osborne is a
director of Custom Building Products, Inc., Global Geophysical
Services, Inc., Karat Acquisition LLC, Shelter Bay Energy Inc.
and Traxys S.A.
Kenneth A. Pontarelli
has been a member of our
board since September 2006 and a member of the board of
directors of Coffeyville Acquisition II and Coffeyville
Acquisition III since October 2007. He has also been a
director of the managing general partner of the Partnership
since October 2007. He also was a member of the board of
directors of Coffeyville Acquisition from June 2005 until
October 2007. Mr. Pontarelli is a partner managing director
in the Merchant Banking Division of Goldman, Sachs &
Co. Mr. Pontarelli joined Goldman, Sachs & Co. in
1992 and became a managing director in 2004. He is a director of
CCS, Inc., Cobalt International Energy, L.P., Energy Future
Holdings Corp., Knight Holdco LLC, and Kinder Morgan, Inc. He
received a B.A. from Syracuse University and an M.B.A. from
Harvard Business School.
Mark E. Tomkins
has been a member of our board
since January 2007. He also was a member of the board of
directors of Coffeyville Acquisition from January 2007 until
October 2007. Mr. Tomkins has served as the senior
financial officer at several large companies during the past ten
years. He was Senior Vice President and Chief Financial Officer
of Innovene, a petroleum refining and chemical polymers business
and a subsidiary of British Petroleum, from May 2005 to January
2006, when Innovene was sold to a strategic buyer. From January
2001 to May 2005 he was Senior Vice President and Chief
Financial Officer of Vulcan Materials Company, a publicly traded
construction materials and chemicals company. From August 1998
to January 2001 Mr. Tomkins was Senior Vice President and
Chief Financial Officer of Chemtura (formerly GreatLakes
Chemical Corporation), a publicly traded specialty chemicals
company. From July 1996 to August 1998 he worked at Honeywell
Corporation as Vice President of Finance and Business
Development for its polymers division and as Vice President of
Finance and Business Development for its electronic materials
division. From November 1990 to July 1996 Mr. Tomkins
worked at Monsanto Company in various financial and accounting
positions, including Chief Financial Officer of the growth
enterprises division from January 1995 to July 1996. Prior to
joining Monsanto he worked at Cobra Corporation and as an
auditor in private practice. Mr. Tomkins received a B.S.
degree in business, with majors in Finance and Management, from
Eastern Illinois University and an M.B.A from Eastern Illinois
University and is a certified public accountant.
Mr. Tomkins is a director of W.R. Grace & Co. and
Elevance Renewable Sciences, Inc.
Board of
Directors
Our board of directors consists of eight members. The current
directors are included above. Our directors are elected annually
to serve until the next annual meeting of stockholders or until
their successors are duly elected and qualified.
Our board has an audit committee, a compensation committee, a
nominating and corporate governance committee and a conflicts
committee. Our board of directors has determined that we are a
controlled company under the rules of the New York
Stock Exchange, and, as a result, qualify for, and may rely on,
exemptions from certain corporate governance requirements of the
New York Stock Exchange. Pursuant to the controlled
company exception to the board of directors and committee
composition requirements, we are exempt from the rules that
require that (a) our board of directors be comprised of a
majority of independent directors, (b) our
compensation committee be comprised
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solely of independent directors and (c) our
nominating and corporate governance committee be comprised
solely of independent directors as defined under the
rules of the New York Stock Exchange. The controlled company
exemption does not modify the independence requirements for the
audit committee. The Sarbanes-Oxley Act and the New York Stock
Exchange rules require that our audit committee be composed
entirely of independent directors, except that our audit
committee is only required to have a majority of independent
directors until October 22, 2008. The audit committee
currently has three members, two of which are independent
directors. Thus, the composition of our audit committee
satisfies the independence requirements of the New York Stock
Exchange and the Sarbanes-Oxley Act. Steve A. Nordaker and Mark
E. Tomkins are the independent directors currently serving on
the audit committee. Our board has affirmatively determined that
Messrs. Steve A. Nordaker and Mark E. Tomkins are
independent directors under the rules of the SEC and the NYSE.
We do not believe that our reliance on the exemption that allows
our audit committee to consist only of a majority of independent
directors until October 22, 2008 will adversely affect the
ability of our audit committee to act independently and to
satisfy applicable independence requirements.
Audit Committee.
The members of the
audit committee are Messrs. Mark Tomkins, Steve A.
Nordaker, and Stanley de J. Osborne. Mr. Tomkins is
chairman of the audit committee. Our board of directors has
determined that Mr. Tomkins qualifies as an audit
committee financial expert. Our board of directors has
also determined that Mr. Nordaker and Mr. Tompkins are
independent directors as discussed above. The audit
committees responsibilities are to review the accounting
and auditing principles and procedures of our company with a
view to providing for the safeguard of our assets and the
reliability of our financial records by assisting the board of
directors in monitoring our financial reporting process,
accounting functions and internal controls; to oversee the
qualifications, independence, appointment, retention,
compensation and performance of our independent registered
public accounting firm; to recommend to the board of directors
the engagement of our independent accountants; to review with
the independent accountants the plans and results of the
auditing engagement; and to oversee whistle-blowing
procedures and certain other compliance matters.
Compensation Committee.
The members of
the compensation committee are Messrs. George E. Matelich,
Steve A. Nordaker, Kenneth Pontarelli and Mark Tomkins.
Mr. George E. Matelich is the chairman of the compensation
committee. The principal responsibilities of the compensation
committee are to establish policies and periodically determine
matters involving executive compensation, recommend changes in
employee benefit programs, grant or recommend the grant of stock
options and stock awards and provide counsel regarding key
personnel selection. A subcommittee of the compensation
committee consisting of Messrs. Nordaker and Tomkins will
make stock and option awards to the extent deemed necessary or
advisable for regulatory purposes. See Compensation
Discussion and Analysis.
Nominating and Corporate Governance
Committee.
The members of the nominating and
corporate governance committee are Messrs. Scott L.
Lebovitz, Stanley de J. Osborne, John J. Lipinski and Regis B.
Lippert. Mr. Scott L. Lebovitz is the chairman of the
nominating and corporate governance committee. The principal
duties of the nominating and corporate governance committee are
to recommend to the board of directors proposed nominees for
election to the board of directors by the stockholders at annual
meetings and to develop and make recommendations to the board of
directors regarding corporate governance matters and practices.
Conflicts Committee.
The members of the
conflicts committee are Messrs. Steve A. Nordaker and Mark
Tomkins. The principal duties of the conflicts committee are to
determine, in accordance with the conflicts of interests policy
adopted by our board of directors, if the resolution of a
conflict of interest between CVR Energy and our subsidiaries, on
the one hand, and the Partnership, the Partnerships
managing general partner or any subsidiary of the Partnership,
on the other hand, is fair and reasonable to us.
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Compensation
Committee Interlocks and Insider Participation
Our compensation committee is comprised of Messrs. George
E. Matelich, Steve A. Nordaker, Kenneth A. Pontarelli and Mark
E. Tomkins. Mr. Matelich is a managing director of
Kelso & Company and Mr. Pontarelli is a partner
managing director in the Merchant Banking Division of Goldman,
Sachs & Co. For a description of the Companys
transactions with certain affiliates of Kelso &
Company and certain affiliates of Goldman, Sachs &
Co., see Certain Relationships and Related Party
Transactions Transactions with the Goldman Sachs
Funds and the Kelso Funds below.
Mr. John J. Lipinski, our chairman of the board and chief
executive officer, is also a director of and serves on the
compensation committee of INTERCAT, Inc., a privately held
company of which Regis B. Lippert, who serves as a director on
our board, is the chief executive officer. Otherwise, no
interlocking relationship exists between our board or
compensation committee and the board of directors or
compensation committee of any other company.
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COMPENSATION
DISCUSSION AND ANALYSIS
Executive
Compensation
Overview
The compensation committee of the board of directors oversees
companywide compensation practices and has specifically
reviewed, developed and administered executive compensation
programs and made recommendations to the board of directors of
Coffeyville Acquisition LLC (prior to our initial public
offering) and CVR Energy (following our initial public offering)
on compensation matters. Messrs. George E. Matelich,
Kenneth Pontarelli and John J. Lipinski served as members of
Coffeyville Acquisition LLCs committee during 2006 and
prior to our initial public offering. Following our initial
public offering, our board of directors established a
compensation committee for CVR Energy comprised of
Messrs. George E. Matelich (as chairperson), Kenneth
Pontarelli, Wesley Clark and Mark Tomkins, which took over the
duties of the compensation committee of the board of directors
of Coffeyville Acquisition LLC. As of June 2008,
Messrs. George E. Matelich (as chairperson), Steve A.
Nordaker, Kenneth Pontarelli and Mark Tomkins are the members of
our compensation committee. For purposes of this Compensation
Discussion and Analysis, the board of directors and
the compensation committee refer to the board of
directors and compensation committee of Coffeyville Acquisition
LLC prior to our initial public offering and CVR Energy
following our initial public offering. The definitions of
certain defined terms used in this Compensation Discussion and
Analysis, including Phantom Unit Plan I, Phantom Unit Plan
II, phantom points, phantom service points, phantom performance
points, common units, profits interests, override units,
operating units and value units, among others, are contained in
the section of this prospectus entitled Glossary of
Selected Terms.
The executive compensation philosophy of the compensation
committee is threefold:
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To align the executive officers interest with that of the
stockholders and stakeholders, which provides long-term economic
benefits to the stockholders;
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To provide competitive financial incentives in the form of
salary, bonuses, and benefits with the goal of retaining and
attracting talented and highly motivated executive
officers; and
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To maintain a compensation program whereby the executive
officers, through exceptional performance and equity ownership,
will have the opportunity to realize economic rewards
commensurate with appropriate gains of other equity holders and
stakeholders.
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The compensation committee reviews and makes recommendations to
the board of directors regarding our overall compensation
strategy and policies, with the full board of directors having
the final authority on compensation matters. The board of
directors may from time to time delegate to the compensation
committee the authority to take actions on specific compensation
matters or with respect to compensation matters for certain
employees or officers. In the past, there has been no such
delegation, but our board of directors may delegate to the
compensation committee, for example, in order to comply with
Section 16 of the Exchange Act or Section 162(m) of
the Internal Revenue Code of 1986 when those laws require
actions by outside or non-employee directors, as applicable.
Rule 16b-3
issued under Section 16 of the Exchange Act provides that
transactions between an issuer and its officers or directors
involving issuer securities may be exempt from
Section 16(b) of the Exchange Act if it meets certain
requirements, one of which is approval by a committee of the
board of directors of the issuer consisting of two or more
non-employee directors. Section 162(m) of the Internal
Revenue Code limits deductions by publicly held corporations for
compensation paid to its covered employees (i.e.,
its chief executive officer and next four highest compensated
officers) to the extent that the employees compensation
for the taxable year exceeds $1,000,000. This limit does not
apply to qualified performance-based compensation,
which requires, among other things, satisfaction of a
performance goal that is established by a committee of the board
of directors consisting of two or more outside directors.
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The compensation committee (1) develops, approves and
oversees policies relating to compensation of our chief
executive officer and other executive officers,
(2) discharges the boards responsibility relating to
the establishment, amendment, modification, or termination of
our 2007 Long Term Incentive Plan, the Coffeyville Resources,
LLC Phantom Unit Appreciation Plan (Plan I) (the Phantom
Unit Plan I) and the Coffeyville Resources, LLC Phantom
Unit Appreciation Plan (Plan II) (the Phantom Unit Plan
II), health and welfare plans, incentive plans, defined
contribution plans (401(k) plans), and any other benefit plan,
program or arrangement which we sponsor or maintain and
(3) discharges the responsibilities of the override unit
committee of the board of directors.
Specifically, the compensation committee reviews and makes
recommendations to the board of directors regarding annual and
long-term performance goals and objectives for the chief
executive officer and our other senior executives; reviews and
makes recommendations to the board of directors regarding the
annual salary, bonus and other incentives and benefits, direct
and indirect, of the chief executive officer and our senior
executives; reviews and authorizes the company to enter into
employment, severance or other compensation agreements with the
chief executive officer and other senior executives; administers
our executive incentive plans, including the Phantom Unit Plan I
and the Phantom Unit Plan II; establishes and periodically
reviews perquisites and fringe benefits policies; reviews
annually the implementation of our company-wide incentive bonus
program; oversees contributions to our 401(k) plan; and performs
such duties and responsibilities as may be assigned by the board
of directors to the compensation committee under the terms of
any executive compensation plan, incentive compensation plan or
equity-based plan and as may be assigned to the compensation
committee with respect to the issuance and management of the
override units in Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC.
The compensation committee has regularly scheduled meetings
concurrent with the board of directors meetings and additionally
meets at other times as needed throughout the year. Frequently
issues are discussed via teleconferencing. The chief executive
officer, while a member of the compensation committee prior to
our becoming a public company, did not participate in the
determination of his own compensation, thereby avoiding any
potential conflict of interest. However, he actively provided
and will continue to provide guidance and recommendations to the
committee regarding the amount and form of the compensation of
the other executive officers and key employees. During 2006 and
prior to our becoming a public company, given that the
compensation committee consisted of senior representatives of
the Goldman Sachs Funds and the Kelso Funds, as well as our
chief executive officer, the board did not change or reject
decisions made by the compensation committee.
Compensation paid to executive officers is closely aligned with
our performance on both a short-term and long-term basis.
Compensation is structured competitively in order to attract,
motivate and retain executive officers and key employees and is
considered crucial to our long-term success and the long-term
enhancement of stockholder value. Compensation is structured to
ensure that the executive officers objectives and rewards
are directly correlated to our long-term objectives and the
executive officers interests are aligned with those of
stockholders. To this end, the compensation committee believes
that the most critical component of compensation is equity
compensation.
The following discusses in detail the foundation underlying and
the drivers of our executive compensation philosophy, and also
how the related decisions are made. Qualitative information
related to the most important factors utilized in the analysis
of these decisions is described.
Elements of
Compensation
The three primary components of the compensation program are
salary, an annual cash incentive bonus, and equity awards.
Executive officers are also provided with benefits that are
generally available to our salaried employees.
While these three components are related, we view them as
separate and analyze them as such. The compensation committee
believes that equity compensation is the primary motivator in
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attracting and retaining executive officers. Salary and cash
incentive bonuses are viewed as secondary; however, the
compensation committee views a competitive level of salary and
cash bonus as critical to retaining talented individuals.
Base
Salary
We fix the base salary of each of our executive officers at a
level that we believe enables us to hire, motivate and retain
individuals in a competitive environment and to reward
satisfactory individual and company performance. In determining
its recommendations for salary levels, the compensation
committee takes into account peer group pay and individual
performance.
With respect to our peer group, management, through the chief
executive officer, provides the compensation committee with
information gathered through a detailed annual review of
executive compensation programs of other publicly and privately
held companies in our industry, which are similar to us in size
and operations (among other factors). In 2007, management
reviewed and provided information to the compensation committee
regarding the salary, bonus and other compensation amounts paid
to named executive officers in respect of 2006 for the following
independent refining companies, which we view as members of our
peer group: Frontier Oil Corporation, Holly Corporation and
Tesoro Corporation. Management also reviewed the following
fertilizer businesses for executives focused on our fertilizer
business: CF Industries Holdings Inc. and Terra Industries, Inc.
It then averaged these peer group salary levels over a number of
years to develop a range of salaries of similarly situated
executives of these companies, and used this range as a factor
in determining base salary (and overall cash compensation) of
the named executive officers. Management also reviewed the
differences in levels of compensation among the named executive
officers of this peer group, and used these differences as a
factor in setting a different level of salary and overall
compensation for each of our named executive officers based on
their relative positions and levels of responsibility.
With respect to individual performance, the compensation
committee considered, among other things, the following specific
achievements over the past 12 months with respect to
Mr. Lipinski.
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Flood Response.
Mr. Lipinski directed the
Companys successful response to an unprecedented flood
which devastated portions of the city of Coffeyville during the
weekend of June 30, 2007 and closed down our refinery and
the nitrogen fertilizer plant. The flood also resulted in a
crude oil discharge from our refinery into the Verdigris River
that required an immediate environmental response. Under
Mr. Lipinskis leadership, the refinery was restored
to full operation in approximately six weeks, and the fertilizer
plant, situated on higher ground, returned to full operation in
approximately 18 days. In addition, Mr. Lipinski
oversaw our efforts to work closely with the EPA and Kansas and
Oklahoma regulators to review and analyze the environmental
effects of the crude oil discharge and coordinate a property
repurchase project in which we purchased approximately 300 homes
from citizens of Coffeyville at their pre-flood values (or
greater). This effort contributed to a successful outcome in our
defense of two class action lawsuits.
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Initial Public Offering.
Mr. Lipinski
supervised the initial filing of our registration statement with
the Securities and Exchange Commission in September 2006 and the
consummation of our initial public offering in October 2007. The
initial public offering process required a large amount of time
and attention due to the turnaround in the first quarter of
2007, the decision to move our nitrogen fertilizer operations
into a limited partnership structure, and the flood which
occurred during the weekend of June 30, 2007. We ultimately
listed our shares of common stock on the New York Stock Exchange
and sold 23 million shares in the offering at an initial
price of $19.00 per share.
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Business Expansion.
Mr. Lipinski directed
the Companys growth strategy beginning in 2005, which
included our refinery expansion project during 2006 and 2007 and
the fertilizer plant UAN expansion project that commenced in
2007. Nearly every process unit at the refinery was involved in
the refinery expansion project, which was consummated in the
fourth quarter of
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2007. Our refinery throughput rates, averaging less than
90,000 bpd prior to June 2005, averaged over
110,000 bpd of crude during the fourth quarter of 2007, a
record rate for our refinery. In addition, the blend of crudes
was optimized to accommodate larger volumes of heavy sour crude.
We processed more than 21,000 bpd of heavy sour crude in
the fourth quarter of 2007, as compared with 2,700 bpd of
heavy sour crude in the first quarter of 2006. Part of this
project also included the addition of a new 24,000 bpd
continuous catalytic reforming (CCR) unit which
replaced an older technology unit two-thirds its size. The new
CCR increased reforming capacity and also over time will produce
more hydrogen, which over time will reduce our refinerys
dependence on the nitrogen fertilizer business for hydrogen
purchases. The fertilizer plant UAN expansion project is
expected to enable the nitrogen fertilizer plant to consume
substantially all of its net ammonia production in the
production of UAN, historically a higher margin product than
ammonia. We estimate that it will result in an approximately 50%
increase in the fertilizer plants annual UAN production.
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With respect to individual performance of Messrs. Riemann,
Rens, Haugen and Daly, the compensation committee considered,
among other things, managements immediate and effective
response to the June 2007 flood, the successful completion of
our initial public offering in October 2007 and the expansion of
our refinerys capacity as evidenced by achievement of
record throughput rates in the fourth quarter of 2007.
Each of the named executive officers has an employment agreement
which sets forth his base salary. Salaries are reviewed annually
by the compensation committee with periodic informal reviews
throughout the year. Adjustments, if any, are usually made on
January 1st of the year immediately following the
review. In the fourth quarter of 2006, the compensation
committee determined that Mr. Haugens base salary
should be increased from $225,000 to $275,000 due to his
increased responsibilities with our Company. The base salaries
of Mr. Lipinski, Mr. Riemann and Mr. Rens were
not adjusted at that time. The compensation committee most
recently reviewed the level of cash salary and bonus for each of
the executive officers in November 2007 and noted certain
changes of responsibilities and promotions. Individual
performance, the practices of our peer group of companies and
changes in an executive officers status were considered,
and each measurement was given relatively equal weight. The
compensation committee recommended that the board of directors
increase the 2008 salaries of Messrs. Lipinski (to $700,000
from $650,000), Riemann (to $375,000 from $350,000) and Rens (to
$300,000 from $250,000), respectively, effective January 1,
2008, due to the increase in the cost of living and in order
align their total compensation with compensation paid by
companies in our peer group. Prior to October 23, 2007,
Mr. Daly did not have an employment agreement with the
Company. His base salary of $215,000 for 2007 was increased to
$220,000 effective January 1, 2008 pursuant to the terms of
the October 23, 2007 employment agreement.
Mr. Haugens salary for 2008 remained at $275,000.
In addition, the compensation committee determined that no
equity awards should be made to the named executive officers in
connection with our initial public offering in 2007. However,
the compensation committee may elect to make restricted stock
grants, option grants or other equity grants during 2008 in its
discretion. In addition, Coffeyville Acquisition III LLC,
which owns the managing general partner of the Partnership, made
limited equity grants of interests in Coffeyville
Acquisition III LLC to the executive officers in 2007.
Annual
Bonus
We use information about total cash compensation paid by members
of our peer group of companies, the composition of which is
discussed above, in determining both the level of bonus award
and the ratio of salary to bonus because we believe that
maintaining a level of bonus and a ratio of fixed salary (which
is fixed and guaranteed) to bonus (which may fluctuate) that is
in line with those of our competitors is an important factor in
retaining the executives. The compensation committee also
desires that a significant portion of our executive
officers compensation package be at risk. That is, a
portion of the executive officers overall compensation
would not be guaranteed and would be
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determined based on individual and company performance. With
respect to individual performance, the compensation committee
considered the specific achievements of our named executive
officers, as described above.
Our program provides for greater potential bonus awards as the
authority and responsibility of a position increase. Our chief
executive officer has the greatest percentage of his
compensation at risk in the form of a discretionary bonus.
Bonuses are determined based on our analysis of the total
compensation packages for executive officers in our peer group.
Our named executive officers retain a significant percentage of
their compensation package at risk in the form of potential
discretionary bonuses.
Bonuses may be paid in an amount equal to the target percentage,
less than the target percentage or greater than the target
percentage based on current year performance as recommended by
the compensation committee. The performance determination takes
into account overall operational performance, financial
performance, factors affecting shareholder value including
growth initiatives, and the individuals personal
performance. The determination of whether the target bonus
amount should be paid is not based on specific metrics, but
rather a general assessment of how the business performed as
compared to the business plan developed for the year. Due to the
nature of the business, financial performance alone may not
dictate or be a fair indicator of the performance of the
executive officers. Conversely, financial performance may exceed
all expectations, but it could be due to outside forces in the
industry rather than true performance by an executive that
exceeds expectations. In order to take this mismatch into
consideration and to assess the executive officers
performance on their own merits, the compensation committee
makes an assessment of the executive officers performance
separate from the actual financial performance of the company,
although such measurement is not based on any specific metrics.
The compensation committee reviewed the individualized
performance and company performance as compared to expectations
for the year ended December 31, 2007. Under their
employment agreements, the 2007 target bonuses were the
following percentages of salary for each of the following:
Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann
(200%), Mr. Haugen (120%) and Mr. Daly (80%). The
bonuses in respect of 2007 performance were greater than target
for Messrs. Lipinski and Rens due to their significant and
continuous involvement in our initial public offering, which was
consummated in October 2007, and due to their effective
leadership role in and their coordination of the effective
response to the flood that occurred during the weekend of
June 30, 2007. Bonuses in respect of 2007 performance were
less than target for Messrs. Riemann and Haugen because of
a review of how the business performed as compared to our
business plan developed for the year. Mr. Dalys bonus
was approximately equivalent to his target bonus amount. Under
their employment agreements, the 2008 target bonuses will be the
following percentages of salary for each of the following:
Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann
(200%), Mr. Haugen (120%) and Mr. Daly (80%).
Annual cash incentive bonuses for our named executive officers
are established as part of their respective individual
employment agreements. Each of these employment agreements
provides that the executive will receive an annual cash
performance bonus determined in the discretion of the board of
directors, with a target bonus amount specified as a percentage
of salary for that executive officer based on individualized
performance goals and company performance goals. In connection
with the review of peer company compensation practices with
respect to total cash compensation paid as described above, in
November 2007, the compensation committee did not adjust the
future target percentage for the performance-based annual cash
bonus for executive officers as the Committee felt such targets
were comparable to, and appropriate with respect to, its peer
companies.
Equity
We use equity incentives to reward long-term performance. The
issuance of equity to executive officers is intended to generate
significant future value for each executive officer if the
companys
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performance is outstanding and the value of the companys
equity increases for all stockholders. The compensation
committee believes that this also promotes long-term retention
of the executive. The equity incentives were negotiated to a
large degree at the time of the acquisition of our business in
June 2005 (with additional units that were not originally
allocated in June 2005 issued in December 2006) in order to
bring the executive officers compensation package in line
with executives at private equity portfolio companies, based on
the private equity market practices at that time.
The greatest share of total compensation to the chief executive
officer and other named executive officers (as well as selected
senior executives and key employees) is in the form of equity:
common units in our two largest stockholders, Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC,
override units within Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and common and override
units in Coffeyville Acquisition III LLC, the entity which
owns the managing general partner of the Partnership which holds
the nitrogen fertilizer business. Any financial obligations
related to such common units and override units reside with the
issuer of such units and not with CVR Energy. Separately,
Coffeyville Resources, LLC, a subsidiary of CVR Energy, issued
phantom points to certain members of management, and any
financial obligations related to such phantom points are the
obligations of CVR Energy. The total number of such awards is
detailed in this prospectus and was approved by the board of
directors.
The limited liability company agreements of Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC provide
the methodology for payouts for most of this equity based
compensation. In general terms, the agreements provide for two
classes of interests in each of Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC: (1) common units and
(2) profits interests, which are called override units (and
consist of both operating units and value units). Each of the
named executive officers has a capital account under which his
balance is increased or decreased to reflect his allocable share
of net income and gross income of Coffeyville Acquisition LLC or
Coffeyville Acquisition II LLC, as applicable, the capital
that the named executive officer contributed in exchange for his
common units, distributions paid to such named executive officer
and his allocable share of net loss and items of gross
deduction. Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC may make distributions to their members
to the extent that the cash available to them is in excess of
the business reasonably anticipated needs. Distributions
are generally made to members capital accounts in
proportion to the number of units each member holds. All cash
payable pursuant to the limited liability company agreements of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC will be paid by Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, respectively, and will not be paid by
CVR Energy. Although CVR Energy is required to recognize a
compensation expense with respect to such awards, CVR Energy
also records a contribution to capital with respect to these
awards, and as a result, there is no cash effect on CVR Energy.
The Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan I) (which we refer to as the Phantom Unit Plan
I) works in correlation with the methodology established by
the Coffeyville Acquisition LLC limited liability company
agreement and the Coffeyville Resources, LLC Phantom Unit
Appreciation Plan (Plan II) (which we refer to as the Phantom
Unit Plan II) works in correlation with the methodology
established by the Coffeyville Acquisition II LLC limited
liability company agreement.
The limited liability company agreement of Coffeyville
Acquisition III LLC provides for two classes of interests
in Coffeyville Acquisition III LLC: (1) common units
and (2) profits interests, which are called override units.
Each of the named executive officers has a capital account under
which his balance is increased or decreased to reflect his
allocable share of net income and gross income of Coffeyville
Acquisition III LLC, the capital that the named executive
officer contributed, distributions paid to such named executive
officer and his allocable share of net loss and items of gross
deduction. Coffeyville Acquisition III LLC may make
distributions to its members to the extent that the cash
available to it is in excess of the business reasonably
anticipated needs. Distributions are generally made to
members capital accounts in proportion to the number of
units each member holds.
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All issuances of override units and phantom points made through
December 31, 2007 were made at what the board of directors
determined to be their fair value on their respective grant
dates. For a more detailed description of these plans, please
see Executive Officers Interests in
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, Executive Officers Interests
in Coffeyville Acquisition III LLC, and
Coffeyville Resources, LLC Phantom Unit
Appreciation Plan (Plan I) and Coffeyville Resources, LLC
Phantom Unit Appreciation Plan (Plan II), below.
Additionally, there was a pool of override units under the
Coffeyville Acquisition LLC limited liability company agreement
that had not been issued as of December 2006. It was the intent
that, upon a filing of a registration statement, the unallocated
override units in the pool would be issued. The compensation
committee recommended that all remaining override units in the
pool available be issued to John J. Lipinski on
December 29, 2006. The compensation committee made its
decision and recommendation to the board of directors to grant
Mr. Lipinski these additional units based on his
accomplishments (and made the decision and recommendation
without any input from Mr. Lipinski). Mr. Lipinski has
been and will continue to be instrumental in positioning the
company to become more competitive and in increasing the
capacity of the refinery operations through his negotiating and
obtaining favorable crude oil pricing, as well as in helping to
gain access to capital in order to expand overall operations of
both segments of our business. The increased value and growth of
the business is directly attributable to the actions and
leadership that Mr. Lipinski has provided for the overall
executive management group.
Additionally, due to the significant contributions of
Mr. Lipinski as reflected above, in December 2006 the
compensation committee awarded him for his services
0.1044200 shares in Coffeyville Refining &
Marketing, Inc. and 0.2125376 shares in Coffeyville
Nitrogen Fertilizers, Inc. This approximated 0.31% and 0.64% of
each companys total shares outstanding, respectively, at
that time. The shares were issued to compensate him for his
exceptional performance related to the operations of the
business. In connection with the formation of Coffeyville
Refining & Marketing Holdings, Inc. in August 2007,
Mr. Lipinskis shares of common stock in Coffeyville
Refining & Marketing, Inc. were exchanged for an
equivalent number of shares of common stock in Coffeyville
Refining & Marketing Holdings, Inc. Prior to our
becoming a public company in October 2007, these shares were
exchanged for 247,471 shares of common stock in CVR Energy
at an equivalent fair market value.
We also established a stock incentive plan in connection with
our initial public offering in October 2007. No awards have been
established at this time for the chief executive officer or
other named executive officers. In keeping with the compensation
committees stated philosophy, such awards will be intended
to help achieve the compensation goals necessary to run our
business. As stated above, the compensation committee may elect
to make awards under this plan in 2008 at its discretion.
Other Forms of
Compensation
Each of our executive officers has a provision in his employment
agreement providing for certain severance benefits in the event
of termination without cause. These severance provisions are
described in the Employment Agreements and Other
Arrangements section below. The severance arrangements
were all negotiated with the original employment agreements
between the executive officer and the company. There are no
change of control arrangements, but the compensation committee
believed that there needed to be some form of compensation upon
certain events of termination of services as is customary for
similar companies.
As a general matter, we do not provide a significant number of
perquisites to named executive officers.
Compensation
Policies and Philosophy
Ours is a commodity business with high volatility and risk where
earnings are not only influenced by margins, but also by unique,
innovative and aggressive actions and business practices on the
part of the executive team. The compensation committee routinely
reviews financial and operational
187
performance compared to our business plan, positive and negative
industry factors, and the response of the senior management team
in dealing with and maximizing operational and financial
performance in the face of otherwise negative situations. Due to
the nature of our business, performance of an individual or the
business as a whole may be outstanding; however, our financial
performance may not depict this same level of achievement. The
financial performance of the company is not necessarily
reflective of individual operational performance. These are some
of the factors used in setting executive compensation. Specific
performance levels or benchmarks are not necessarily used to
establish compensation; however, the compensation committee
takes into account all factors to make a subjective
determination of related compensation packages for the executive
officers.
The compensation committee has not adopted any formal or
informal policies or guidelines for allocating compensation
between long-term and current compensation, between cash and
non-cash compensation, or among different forms of compensation
other than its belief that the most crucial component is equity
compensation. The decision is strictly made on a subjective and
individual basis considering all relevant facts.
For compensation decisions, including decisions regarding the
grant of equity compensation relating to executive officers
(other than our chief executive officer and chief operating
officer), the compensation committee typically considers the
recommendations of our chief executive officer.
In recommending compensation levels and practices, our
management reviews peer group compensation practices based on
publicly available data. The analysis is done in-house in its
entirety and is reviewed by executive officers who are not
members of the compensation committee. The analysis is based on
public information available through proxy statements and
similar sources. Because the analysis is almost always performed
based on prior year public information, it may often be somewhat
outdated. We have not historically and at this time do not
intend to hire or rely on independent consultants to analyze or
prepare formal surveys for us. We do receive certain unsolicited
executive compensation surveys; however, our use of these is
limited as we believe we need to determine our baseline based on
practices of other companies in our industry.
Because we are now a public company, Section 162(m) of the
Internal Revenue Code limits the deductibility of compensation
in excess of $1 million paid out to our executive officers
unless specific and detailed criteria are satisfied. We believe
that it is in our best interest to deduct compensation paid to
our executive officers. We will consider the anticipated tax
treatment to the company and our executive officers in the
review and determination of the compensation payments and
incentives. No assurance, however, can be given that the
compensation will be fully deductible under Section 162(m).
Nitrogen
Fertilizer Limited Partnership
A number of our executive officers, including our chief
executive officer, chief operating officer, chief financial
officer, general counsel, executive vice president/general
manager for nitrogen fertilizer, and vice president,
environmental, health and safety, serve as executive officers
for both our company and the Partnership. These executive
officers receive all of their compensation and benefits from us,
including compensation related to services for the Partnership,
and are not paid by the Partnership or its managing general
partner. However, the Partnership or the managing general
partner must reimburse us pursuant to a services agreement for
the time our executive officers spend working for the
Partnership. The percentage of each named executive
officers compensation that represents the services
provided to the Partnership in 2007 are approximately as
follows: John J. Lipinski (25%), Stanley A. Riemann (40%), James
T. Rens (35%), Robert W. Haugen (5%) and Daniel J.
Daly, Jr. (10%).
We have entered into a services agreement with the Partnership
and its managing general partner in which we have agreed to
provide management services to the Partnership for the operation
of the nitrogen fertilizer business. Under this agreement, any
of the Partnership, its managing general partner or Coffeyville
Resources Nitrogen Fertilizers, LLC, a subsidiary of the
Partnership, are required to pay
188
us (i) all costs incurred by us in connection with the
employment of our employees, other than administrative
personnel, who provide services to the Partnership under the
agreement on a full-time basis, but excluding share-based
compensation; (ii) a prorated share of costs incurred by us
in connection with the employment of our employees, other than
administrative personnel, who provide services to the
Partnership under the agreement on a part-time basis, but
excluding share-based compensation, and such prorated share must
be determined by us on a commercially reasonable basis, based on
the percent of total working time that such shared personnel are
engaged in performing services for the Partnership; (iii) a
prorated share of certain administrative costs; and
(iv) various other administrative costs in accordance with
the terms of the agreement. Either we or the managing general
partner of the Partnership may terminate the agreement upon at
least 90 days notice.
Summary
Compensation Table
The following table sets forth certain information with respect
to compensation for the years ended December 31, 2006 and
December 31, 2007 earned by our chief executive officer,
our chief financial officer and our three other most highly
compensated executive officers as of December 31, 2007. In
this prospectus, we refer to these individuals as our named
executive officers.
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Non-Equity
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Stock
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Incentive Plan
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All Other
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Name and Principal Position
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Year
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Salary
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Bonus(1)
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Awards(3)
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Compensation(1)(4)
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Compensation(5)
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Total
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John J. Lipinski
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2007
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$
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650,000
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$
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1,850,000
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$
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12,189,955
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(6)
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$
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14,689,955
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Chief Executive Officer
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2006
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$
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650,000
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$
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1,331,790
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$
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4,326,188
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$
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487,500
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$
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5,007,935
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(7)
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$
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11,803,413
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James T. Rens
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2007
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$
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250,000
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$
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400,000
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$
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2,761,144
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(8)
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$
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3,411,144
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Chief Financial Officer
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2006
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$
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250,000
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$
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205,000
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$
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130,000
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$
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695,316
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(9)
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$
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1,280,316
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Stanley A. Riemann
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2007
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$
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350,000
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$
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722,917
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(2)
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$
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4,911,011
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(10)
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$
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5,983,928
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Chief Operating Officer
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2006
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$
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350,000
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$
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772,917
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(2)
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$
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210,000
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$
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943,789
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(11)
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$
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2,276,706
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Robert W. Haugen
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2007
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$
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275,000
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$
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230,000
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$
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2,822,978
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(12)
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$
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3,327,978
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Executive Vice President,
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2006
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$
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225,000
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$
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205,000
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$
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117,000
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$
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695,471
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(13)
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$
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1,242,471
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Refining Operations
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Daniel J. Daly, Jr.
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2007
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$
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215,000
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$
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200,000
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$
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2,355,059
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(14)
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$
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2,770,059
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Executive Vice President,
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2006
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$
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185,000
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$
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175,000
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$
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96,200
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$
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714,705
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(15)
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$
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1,170,905
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Strategy
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(1)
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Bonuses are reported for the year in which they were earned,
though they may have been paid the following year.
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(2)
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Includes a retention bonus in the amount of $122,917.
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(3)
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Reflects the amount recognized for financial statement reporting
purposes for the fiscal years ended December 31, 2006 and
December 31, 2007 with respect to shares of common stock of
each of Coffeyville Refining & Marketing, Inc. and
Coffeyville Nitrogen Fertilizers, Inc. granted to
Mr. Lipinski effective December 28, 2006. In
connection with the formation of Coffeyville
Refining & Marketing Holdings, Inc. in August 2007,
Mr. Lipinskis shares of common stock in Coffeyville
Refining & Marketing, Inc. were exchanged for an
equivalent number of shares of common stock in Coffeyville
Refining & Marketing Holdings, Inc. In connection with
our initial public offering in October 2007,
Mr. Lipinskis shares of common stock in Coffeyville
Refining & Marketing Holdings, Inc. were exchanged by
Mr. Lipinski for 247,471 shares of our common stock.
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(4)
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Reflects cash awards to the named individuals in respect of 2006
performance pursuant to our Variable Compensation Plan.
Beginning in 2007, our executive officers no longer participated
in this plan.
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(5)
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The amounts shown represent grants of profits interests in
Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC
and Coffeyville Acquisition III LLC and grants of phantom
points in Phantom Unit Plan I and Phantom Unit Plan II and
reflect the dollar amounts recognized for financial statement
reporting purposes for the years ended December 31, 2006
and December 31, 2007 in accordance with SFAS 123(R).
For the 2006 amounts, assumptions used in the calculation are
included in footnote 5 to our audited financial statements for
the year ended December 31, 2006 included in the
Companys registration statement on
Form S-1/A
filed on October 16, 2007. For
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the 2007 amounts, assumptions used in the calculation are
included in footnote 3 to our audited financial statements for
the year ended December 31, 2007 included elsewhere in this
prospectus. The profits interests in Coffeyville Acquisition
LLC, Coffeyville Acquisition II LLC and Coffeyville
Acquisition III LLC and the phantom points in Phantom Unit
Plan I and Phantom Unit Plan II are more fully described
below under Executive Officers Interests
in Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, Executive
Officers Interests in Coffeyville Acquisition III
LLC, and Coffeyville Resources, LLC
Phantom Unit Appreciation Plan (Plan I) and Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan II).
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(6)
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Includes (a) a company contribution under our 401(k) plan
in 2007, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2007, (c) the premiums paid for by us on behalf
of the executive officer with respect to our basic life
insurance program, (d) profits interests in Coffeyville
Acquisition LLC that were granted in 2005 in the amount of
$8,057,632, (e) profits interests in Coffeyville
Acquisition LLC that were granted on December 29, 2006 in
the amount of $1,595,428, (f) profits interests in
Coffeyville Acquisition III LLC that were granted in
October 2007 in the amount of $1,080 and (g) phantom points
granted during the period ending December 31, 2006 in the
amount of $2,519,640.
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(7)
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Includes (a) a company contribution under our 401(k) plan
in 2006, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2006, (c) forgiveness of a note that
Mr. Lipinski owed to Coffeyville Acquisition LLC in the
amount of $350,000, (d) forgiveness of accrued interest
related to the forgiven note in the amount of $17,989,
(e) profits interests in Coffeyville Acquisition LLC
granted in 2005 in the amount of $630,059, (f) a cash
payment in respect of taxes payable on his December 28,
2006 grant of subsidiary stock in the amount of $2,481,346,
(g) profits interests in Coffeyville Acquisition LLC that
were granted on December 29, 2006 in the amount of $20,510
and (h) phantom points granted during the period ending
December 31, 2006 in the amount of $1,495,211.
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(8)
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Includes (a) a company contribution under our 401(k) plan
in 2007, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2007, (c) the premiums paid for by us on behalf
of the executive officer with respect to our basic life
insurance program, (d) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $1,836,087,
(e) profits interests in Coffeyville Acquisition III
LLC that were granted in October 2007 in the amount of $201 and
(f) phantom points granted to Mr. Rens during the
period ending December 31, 2006 in the amount of $911,768.
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(9)
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Includes (a) a company contribution under our 401(k) plan
in 2006, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2006, (c) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $279,670 and
(d) phantom points granted to Mr. Rens during the
period ending December 31, 2006 in the amount of $651,299.
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(10)
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Includes (a) a company contribution under our 401(k) plan
in 2007, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2007, (c) the premiums paid for by us on behalf
of the executive officer with respect to our basic life
insurance program (d) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $3,576,617,
(e) profits interests in Coffeyville Acquisition III
LLC that were granted in October 2007 in the amount of $393,
(f) phantom points granted to Mr. Riemann during the
period ending December 31, 2006 in the amount of $1,097,527
and (g) a relocation bonus of $222,099.
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(11)
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Includes (a) a company contribution under our 401(k) plan
in 2006, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2006, (c) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $143,571 and
(d) phantom points granted to Mr. Riemann during the
period ending December 31, 2006 in the amount of $541,061.
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(12)
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Includes (a) a company contribution under our 401(k) plan
in 2007, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2007, (c) the premiums paid for by us on behalf
of the executive officer with respect to our basic life
insurance program (d) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $1,836,087,
(e) profits interests in Coffeyville Acquisition III
LLC that were granted in October 2007 in the amount of $201,
(f) phantom points granted to Mr. Haugen during the
period ending December 31, 2006 in the amount of $911,768
and (g) a relocation bonus of $61,500.
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(13)
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Includes (a) a company contribution under our 401(k) plan
in 2006, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2006, (c) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $143,571 and
(d) phantom points granted to Mr. Haugen during the
period ending December 31, 2006 in the amount of $541,061.
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(14)
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Includes (a) a company contribution under our 401(k) plan
in 2007, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2007, (c) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $1,324,168,
(d) profits interests in Coffeyville Acquisition III
LLC that were granted in October 2007 in the amount of $144 and
(e) phantom points granted to Mr. Daly during the
period ending December 31, 2006 in the amount of $1,016,972.
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(15)
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Includes (a) a company contribution under our 401(k) plan
in 2006, (b) the premiums paid by us on behalf of the
executive officer with respect to our executive life insurance
program in 2006, (c) profits interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $103,543 and
(d) phantom points granted to Mr. Daly during the
period ending December 31, 2006 in the amount of $603,491.
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Employment
Agreements and Other Arrangements
Employment
Agreements
John J. Lipinski.
On July 12,
2005, Coffeyville Resources, LLC entered into an employment
agreement with Mr. Lipinski, as Chief Executive Officer,
which was subsequently assumed by CVR Energy and amended and
restated effective as of December 29, 2007. The agreement
has a rolling term of three years so that at the end of each
month it automatically renews for one additional month, unless
otherwise terminated by CVR Energy or Mr. Lipinski.
Mr. Lipinski receives an annual base salary of $700,000.
Mr. Lipinski is eligible to receive a performance-based
annual cash bonus with a target payment equal to 250% of his
annual base salary to be based upon individual
and/or
company performance criteria as established by our board of
directors for each fiscal year.
Mr. Lipinskis agreement provides for certain
severance payments that may be due following the termination of
his employment. These benefits are described below under
Potential Payments Upon Termination or
Change-of-Control.
Stanley A. Riemann, James T. Rens, Robert W. Haugen and
Daniel J. Daly, Jr.
On July 12,
2005, Coffeyville Resources, LLC entered into employment
agreements with each of Mr. Riemann, Mr. Rens, and
Mr. Haugen. The agreements were subsequently assumed by CVR
Energy and amended and rested effective as of December 29,
2007. The agreements have a term of three years and expire in
December 2010, unless otherwise terminated earlier by the
parties. CVR Energy entered into an employment agreement with
Mr. Daly on October 23, 2007 and amended that
agreement as of November 30, 2007. The agreements provide
for an annual base salary of $375,000 for Mr. Riemann,
$300,000 for Mr. Rens, $275,000 for Mr. Haugen and
$220,000 for Mr. Daly. Each executive officer is eligible
to receive a performance-based annual cash bonus to be based
upon individual
and/or
company performance criteria as established by the board of
directors of Coffeyville Resources, LLC for each fiscal year.
The target annual bonus percentages are as follows:
Mr. Riemann (200%), Mr. Rens (120%), Mr. Haugen
(120%) and Mr. Daly (80%).
191
These agreements provide for certain severance payments that may
be due following the termination of the executive officers
employment. These benefits are described below under
Potential Payments Upon Termination or Change
of Control.
Long Term
Incentive Plan
The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP,
permits the grant of options, stock appreciation rights, or
SARs, restricted stock, restricted stock units, dividend
equivalent rights, share awards and performance awards
(including performance share units, performance units and
performance-based restricted stock). Individuals who are
eligible to receive awards and grants under the LTIP include our
and our subsidiaries employees, officers, consultants,
advisors and directors. A summary of the principal features of
the LTIP is provided below. As of December 31, 2007, no
awards had been made under the LTIP to any of our executive
officers.
Shares Available for Issuance.
The LTIP
authorizes a share pool of 7,500,000 shares of our common
stock, 1,000,000 of which may be issued in respect of incentive
stock options. Whenever any outstanding award granted under the
LTIP expires, is canceled, is settled in cash or is otherwise
terminated for any reason without having been exercised or
payment having been made in respect of the entire award, the
number of shares available for issuance under the LTIP shall be
increased by the number of shares previously allocable to the
expired, canceled, settled or otherwise terminated portion of
the award. As of December 31, 2007, 7,463,600 shares
of common stock were available for issuance under the LTIP.
Administration and Eligibility.
The LTIP is
administered by a committee, which is currently the compensation
committee. The committee determines who is eligible to
participate in the LTIP, determines the types of awards to be
granted, prescribes the terms and conditions of all awards, and
construes and interprets the terms of the LTIP. All decisions
made by the committee are final, binding and conclusive.
Award Limits.
In any three calendar year
period, no participant may be granted awards in respect of more
than 6,000,000 shares in the form of (i) stock
options, (ii) SARs, (iii) performance-based restricted
stock and (iv) performance share units, with the above
limit subject to the adjustment provisions discussed below. The
maximum dollar amount of cash or the fair market value of shares
that any participant may receive in any calendar year in respect
of performance units may not exceed $3,000,000.
Type of Awards.
Below is a description of the
types of awards available for grant pursuant to the LTIP.
Stock Options.
The compensation committee is
authorized to grant stock options to participants. The stock
options may be either nonqualified stock options or incentive
stock options. The exercise price of any stock option must be
equal to or greater than the fair market value of a share on the
date the stock option is granted. The term of a stock option
cannot exceed 10 years (except that options may be
exercised for up to 1 year following the death of a
participant even, with respect to nonqualified stock options, if
such period extends beyond the 10 year term). Subject to
the terms of the LTIP, the options terms and conditions,
which include but are no limited to, exercise price, vesting,
treatment of the award upon termination of employment, and
expiration of the option, are determined by the committee and
will be set forth in an award agreement. Payment for shares
purchased upon exercise of an option must be made in full at the
time of purchase. The exercise price may be paid (i) in
cash or its equivalent (e.g., check), (ii) in shares of our
common stock already owned by the participant, on terms
determined by the committee, (iii) in the form of other
property as determined by the committee, (iv) through
participation in a cashless exercise procedure
involving a broker or (v) by a combination of the foregoing.
SARs.
The compensation committee may, in its
discretion, either alone or in connection with the grant of an
option, grant a SAR to a participant. The terms and conditions
of the award will be set
192
forth in an award agreement. SARs may be exercised at such times
and be subject to such other terms, conditions, and provisions
as the committee may impose. SARs that are granted in tandem
with an option may only be exercised upon the surrender of the
right to purchase an equivalent number of shares of our common
stock under the related option and may be exercised only with
respect to the shares of our common stock for which the related
option is then exercisable. The committee may establish a
maximum amount per share that would be payable upon exercise of
a SAR. A SAR entitles the participant to receive, on exercise of
the SAR, an amount equal to the product of (i) the excess
of the fair market value of a share of our common stock on the
date preceding the date of surrender over the fair market value
of a share of our common stock on the date the SAR was issued,
or, if the SAR is related to an option, the per-share exercise
price of the option and (ii) the number of shares of our
common stock subject to the SAR or portion thereof being
exercised. Subject to the discretion of the committee, payment
of a SAR may be made (i) in cash, (ii) in shares of
our common stock or (iii) in a combination of both
(i) and (ii).
Dividend Equivalent Rights.
The compensation
committee may grant dividend equivalent rights either in tandem
with an award or as a separate award. The terms and conditions
applicable to each dividend equivalent right would be specified
in an award agreement. Amounts payable in respect of dividend
equivalent rights may be payable currently or, if applicable,
deferred until the lapsing of restrictions on the dividend
equivalent rights or until the vesting, exercise, payment,
settlement or other lapse of restrictions on the award to which
the dividend equivalent rights relate.
Service Based Restricted Stock and Restricted Stock Units. The
compensation committee may grant awards of time-based restricted
stock and restricted stock units. Restricted stock and
restricted stock units may not be sold, transferred, pledged or
otherwise transferred until the time, or until the satisfaction
of such other terms, conditions and provisions, as the committee
may determine. When the period of restriction on restricted
stock terminates, unrestricted shares of our common stock will
be delivered. Unless the committee otherwise determines at the
time of grant, restricted stock carries with it full voting
rights and other rights as a stockholder, including rights to
receive dividends and other distributions. At the time an award
of restricted stock is granted, the committee may determine that
the payment to the participant of dividends be deferred until
the lapsing of the restrictions imposed upon the shares and
whether deferred dividends are to be converted into additional
shares of restricted stock or held in cash. The deferred
dividends would be subject to the same forfeiture restrictions
and restrictions on transferability as the restricted stock with
respect to which they were paid. Each restricted stock unit
represents the right of the participant to receive a payment
upon vesting of the restricted stock unit or on any later date
specified by the committee. The payment will equal the fair
market value of a share of common stock as of the date the
restricted stock unit was granted, the vesting date or such
other date as determined by the committee at the time the
restricted stock unit was granted. At the time of grant, the
committee may provide a limitation on the amount payable in
respect of each restricted stock unit. The committee may provide
for a payment in respect of restricted stock unit awards
(i) in cash or (ii) in shares of our common stock
having a fair market value equal to the payment to which the
participant has become entitled.
Share Awards.
The compensation committee may
award shares to participants as additional compensation for
service to us or a subsidiary or in lieu of cash or other
compensation to which participants have become entitled. Share
awards may be subject to other terms and conditions, which may
vary from time to time and among participants, as the committee
determines to be appropriate.
Performance Share Units and Performance
Units.
Performance share unit awards and
performance unit awards may be granted by the compensation
committee under the LTIP. Performance share units are
denominated in shares and represent the right to receive a
payment in an amount based on the fair market value of a share
on the date the performance share units were granted, become
vested or any other date specified by the committee, or a
percentage of such amount depending on the level of performance
goals attained. Performance units are denominated in a specified
dollar amount and represent the right to receive a payment of
the specified dollar amount or a percentage of the specified
dollar amount, depending on the level of performance goals
attained.
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Such awards would be earned only if performance goals
established for performance periods are met. A minimum one-year
performance period is required. At the time of grant the
committee may establish a maximum amount payable in respect of a
vested performance share or performance unit. The committee may
provide for payment (i) in cash, (ii) in shares of our
common stock having a fair market value equal to the payment to
which the participant has become entitled or (iii) by a
combination of both (i) and (ii).
Performance-Based Restricted Stock.
The
compensation committee may grant awards of performance-based
restricted stock. The terms and conditions of such award will be
set forth in an award agreement. Such awards would be earned
only if performance goals established for performance periods
are met. Upon the lapse of the restrictions, the committee will
deliver a stock certificate or evidence of book entry shares to
the participant. Awards of performance-based restricted stock
will be subject to a minimum one-year performance cycle. At the
time an award of performance-based restricted stock is granted,
the committee may determine that the payment to the participant
of dividends will be deferred until the lapsing of the
restrictions imposed upon the performance-based restricted stock
and whether deferred dividends are to be converted into
additional shares of performance-based restricted stock or held
in cash.
Performance Objectives.
Performance share
units, performance units and performance-based restricted stock
awards under the LTIP may be made subject to the attainment of
performance goals based on one or more of the following business
criteria: (i) stock price; (ii) earnings per share;
(iii) operating income; (iv) return on equity or
assets; (v) cash flow; (vi) earnings before interest,
taxes, depreciation and amortization, or EBITDA;
(vii) revenues; (viii) overall revenue or sales
growth; (ix) expense reduction or management;
(x) market position; (xi) total stockholder return;
(xii) return on investment; (xiii) earnings before
interest and taxes, or EBIT; (xiv) net income;
(xv) return on net assets; (xvi) economic value added;
(xvii) stockholder value added; (xviii) cash flow
return on investment; (xix) net operating profit;
(xx) net operating profit after tax; (xxi) return on
capital; (xxii) return on invested capital; or
(xxiii) any combination, including one or more ratios, of
the foregoing.
Performance criteria may be in respect of our performance, that
of any of our subsidiaries, that of any of our divisions or any
combination of the foregoing. Performance criteria may be
absolute or relative (to our prior performance or to the
performance of one or more other entities or external indices)
and may be expressed in terms of a progression within a
specified range. The compensation committee may, at the time
performance criteria in respect of a performance award are
established, provide for the manner in which performance will be
measured against the performance criteria to reflect the effects
of extraordinary items, gain or loss on the disposal of a
business segment (other than the provisions for operating losses
or income during the phase-out), unusual or infrequently
occurring events and transactions that have been publicly
disclosed, changes in accounting principles, the impact of
specified corporate transactions (such as a stock split or stock
dividend), special charges and tax law changes, all as
determined in accordance with generally accepted accounting
principles (to the extent applicable).
Amendment and Termination of the LTIP.
Our
board of directors has the right to amend the LTIP except that
our board of directors may not amend the LTIP in a manner that
would impair or adversely affect the rights of the holder of an
award without the award holders consent. In addition, our
board of directors may not amend the LTIP absent stockholder
approval to the extent such approval is required by applicable
law, regulation or exchange requirement. The LTIP will terminate
on the tenth anniversary of the date of stockholder approval.
The board of directors may terminate the LTIP at any earlier
time except that termination cannot in any manner impair or
adversely affect the rights of the holder of an award without
the award holders consent.
Repricing of Options or SARs.
Unless our
stockholders approve such adjustment, the compensation committee
will not have authority to make any adjustments to options or
SARs that would
194
reduce or would have the effect of reducing the exercise price
of an option or SAR previously granted under the LTIP.
Change in Control.
The effect, if any, of a
change in control on each of the awards granted under the LTIP
may be set forth in the applicable award agreement.
Adjustments.
In the event of a
reclassification, recapitalization, merger, consolidation,
reorganization, spin-off,
split-up,
stock dividend, stock split or reverse stock split, or similar
transaction or other change in corporate structure affecting our
common stock, adjustments and other substitutions will be made
to the LTIP, including adjustments in the maximum number of
shares subject to the LTIP and other numerical limitations.
Adjustments will also be made to awards under the LTIP as the
compensation committee determines appropriate. In the event of
our merger or consolidation, liquidation or dissolution,
outstanding options and awards will either be treated as
provided for in the agreement entered into in connection with
the transaction (which may include the accelerated vesting and
cancellation of the options and SARs or the cancellation of
options and SARs for payment of the excess, if any, of the
consideration paid to stockholders in the transaction over the
exercise price of the options or SARs), or converted into
options or awards in respect of the same securities, cash,
property or other consideration that stockholders received in
connection with the transaction.
Executive
Officers Interests in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC
The following is a summary of the material terms of the
Coffeyville Acquisition LLC Second Amended and Restated Limited
Liability Company Agreement and the Coffeyville
Acquisition II LLC Agreement as they relate to the limited
liability company interests granted to our named executive
officers pursuant to those agreements as of December 31,
2007. We refer to the limited liability company agreements of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC collectively as the LLC Agreements. The terms of the two
limited liability company agreements which relate to the
interests granted to our named executive officers are identical
to each other.
General.
The LLC Agreements provide for two
classes of interests in the respective limited liability
companies: (i) common units and (ii) profits
interests, which are called override units (which consist of
both operating units and value units) (common units and override
units are collectively referred to as units). The
common units provide for voting rights and have rights with
respect to profits and losses of, and distributions from,
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, as applicable. Such voting rights cease, however, if the
executive officer holding common units ceases to provide
services to Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, as applicable, or one of its or their
subsidiaries. The common units were issued to our named
executive officers in the following amounts (as subsequently
adjusted) in exchange for capital contributions in the following
amounts: Mr. Lipinski (capital contribution of $650,000 in
exchange for 57,446 units), Mr. Riemann (capital
contribution of $400,000 in exchange for 35,352 units),
Mr. Rens (capital contribution of $250,000 in exchange for
22,095 units), Mr. Haugen (capital contribution of
$100,000 in exchange for 8,838 units) and Mr. Daly
(capital contribution of $50,000 in exchange for
4,419 units). These named executive officers were also
granted override units, which consist of operating units and
value units, in the following amounts: Mr. Lipinski (an
initial grant of 315,818 operating units and 631,637 value units
and a December 2006 grant of 72,492 operating units and 144,966
value units), Mr. Riemann (140,185 operating units and
280,371 value units), Mr. Rens (71,965 operating units and
143,931 value units), Mr. Haugen (71,965 operating units
and 143,931 value units) and Mr. Daly (51,901 operating
units and 103,801 value units). Override units have no voting
rights attached to them, but have rights with respect to profits
and losses of, and distributions from, Coffeyville Acquisition
LLC or Coffeyville Acquisition II LLC, as applicable. Our
named executive officers were not required to make any capital
contribution with respect to the override units; override units
were issued only to certain members of management who own common
units and who agreed to provide services to Coffeyville
Acquisition LLC or Coffeyville Acquisition II LLC, as
applicable.
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In addition, common units were issued to the following executive
officers in the following amounts (as subsequently adjusted) in
exchange for the following capital contributions: Mr. Kevan
Vick (capital contribution of $250,000 in exchange for
22,095 units), Mr. Edmund Gross (capital contribution
of $30,000 in exchange for 2,651 units),
Mr. Christopher Swanberg (capital contribution of $25,000
in exchange for 2,209 units) and Mr. Wyatt Jernigan
(capital contribution of $100,000 in exchange for
8,838 units). Also, Mr. Vick was granted 71,965
operating units and 143,931 value units and Mr. Jernigan
was granted 71,965 operating units and 143,931 value units.
If all of the shares of common stock of our Company held by
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC were sold at $24.92 per share, which was the price of our
common stock on June 16, 2008, and cash was distributed to
members pursuant to the limited liability company agreements of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, our named executive officers would receive a cash payment
in respect of their override units in the following approximate
amounts: Mr. Lipinski ($66.0 million),
Mr. Riemann ($25.7 million), Mr. Rens
($13.2 million), Mr. Haugen ($13.2 million), and
Mr. Daly ($9.5 million).
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC expect to distribute the proceeds of the sale of common
stock in this offering to their members pursuant to their
respective limited liability company agreements. Assuming the
underwriters option to purchase additional shares is not
exercised, if all of the shares of common stock of our Company
to be sold in this offering by Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC were sold at $24.92 per
share, which was the price of our common stock on June 16,
2008, each of our named executive officers will receive a cash
payment in respect of their override units in the following
approximate amounts: Mr. Lipinski ($3.5 million),
Mr. Riemann ($1.6 million), Mr. Rens
($0.9 million), Mr. Haugen ($0.7 million), and
Mr. Daly ($0.5 million).
Forfeiture of Override Units Upon Termination of
Employment.
If the executive officer ceases to
provide services to Coffeyville Acquisition LLC or Coffeyville
Acquisition II LLC, as applicable, or a subsidiary due to a
termination for cause (as such term is defined in
the LLC Agreements), the executive officer will forfeit all of
his override units. If the executive officer ceases to provide
services for any reason other than cause before the fifth
anniversary of the date of grant of his operating units, and
provided that an event that is an Exit Event (as
such term is defined in the LLC Agreements) has not yet occurred
and there is no definitive agreement in effect regarding a
transaction that would constitute an Exit Event, then
(a) unless the termination was due to the executive
officers death or disability (as that term is
defined in the LLC Agreements), in which case a different
vesting schedule will apply based on when the death or
disability occurs, all value units will be forfeited and
(b) a percentage of the operating units will be forfeited
according to the following schedule: if terminated before the
second anniversary of the date of grant, 100% of operating units
are forfeited; if terminated on or after the second anniversary
of the date of grant, but before the third anniversary of the
date of grant, 75% of operating units are forfeited; if
terminated on or after the third anniversary of the date of
grant, but before the fourth anniversary of the date of grant,
50% of operating units are forfeited; and if terminated on or
after the fourth anniversary of the date of grant, but before
the fifth anniversary of the date of grant, 25% of his operating
units are forfeited.
Adjustments to Capital Accounts;
Distributions.
Each of the executive officers has
a capital account under which his balance is increased or
decreased, as applicable, to reflect his allocable share of net
income and gross income of Coffeyville Acquisition LLC or
Coffeyville Acquisition II LLC, as applicable, the capital
that the executive officer contributed, distributions paid to
such executive officer and his allocable share of net loss and
items of gross deduction.
Value units owned by the executive officers do not participate
in distributions under the LLC Agreements until the
Current Value is at least two times the
Initial Price (as these terms are defined in the LLC
Agreements), with full participation occurring when the Current
Value is four times the Initial Price and pro rata distributions
when the Current Value is between two and four times the Initial
Price. Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC may make distributions to
196
their members to the extent that the cash available to them is
in excess of the applicable business reasonably
anticipated needs. Distributions are generally made to
members capital accounts in proportion to the number of
units each member holds. Distributions in respect of override
units (both operating units and value units), however, will be
reduced until the total reductions in proposed distributions in
respect of the override units equals the Benchmark Amount (i.e.,
$11.31 for override units granted on July 25, 2005 and
$34.72 for Mr. Lipinskis later grant). The boards of
directors of Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC will determine the Benchmark
Amount with respect to each override unit at the time of
its grant. There is also a
catch-up
provision with respect to any value unit that was not previously
entitled to participate in a distribution because the Current
Value was not at least four times the Initial Price.
Other Provisions Relating to Units.
The
executive officers are subject to transfer restrictions on their
units, although they may make certain transfers of their units
for estate planning purposes.
Executive
Officers Interests in Coffeyville Acquisition III
LLC
Coffeyville Acquisition III LLC, the sole owner of the
managing general partner of the Partnership, is owned by the
Goldman Sachs Funds, the Kelso Funds, our executive officers,
Mr. Wesley Clark, Magnetite Asset Investors III L.L.C.
and certain members of our senior management team. The following
is a summary of the material terms of the Coffeyville
Acquisition III LLC limited liability company agreement as
they relate to the limited liability company interests held by
our executive officers.
General.
The Coffeyville Acquisition III
LLC limited liability company agreement provides for two classes
of interests in Coffeyville Acquisition III LLC:
(i) common units and (ii) profits interests, which are
called override units.
The common units provide for voting rights and have rights with
respect to profits and losses of, and distributions from,
Coffeyville Acquisition III LLC. Such voting rights cease,
however, if the executive officer holding common units ceases to
provide services to Coffeyville Acquisition III LLC or one
of its subsidiaries. In October 2007, CVR Energys
executive officers made the following capital contributions to
Coffeyville Acquisition III LLC and received a number of
Coffeyville Acquisition III LLC common units equal to their
pro rata portion of all contributions: Mr. Lipinski
($68,146), Mr. Riemann ($16,360), Mr. Rens ($10,225),
Mr. Haugen ($4,090), Mr. Daly ($2,045),
Mr. Jernigan ($4,090), Mr. Gross ($1,227),
Mr. Vick ($10,225) and Mr. Swanberg ($1,022).
Override units have no voting rights attached to them, but have
rights with respect to profits and losses of, and distributions
from, Coffeyville Acquisition III LLC. The override units
have the following terms:
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Approximately 25% of all of the override units have been awarded
to members of our management team. These override units
automatically vested. These units will be owned by the members
of our management team even if they no longer perform services
for us or are no longer employed by us. The following executive
officers received the following grants of this category of
override units: Mr. Lipinski (81,250), Mr. Riemann
(30,000), Mr. Rens (16,634), Mr. Haugen (16,634),
Mr. Jernigan (14,374), Mr. Gross (8,786),
Mr. Vick (13,405), Mr. Swanberg (8,786) and
Mr. Daly (13,269).
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Approximately 75% of the override units have been awarded to
members of our management team responsible for the growth of the
nitrogen fertilizer business. Some portion of these units may be
awarded to members of management added in the future. These
units vest on a five-year schedule, with 33.3% vesting on the
third anniversary of the closing date of the Partnerships
initial public offering (if any such offering occurs), an
additional 33.4% vesting on the fourth anniversary of the
closing date of such an offering, and the remaining 33.3%
vesting on the fifth anniversary of the closing date of such an
offering. Override units are entitled to distributions whether
or not they have vested. Management members will forfeit
unvested units if they are no longer employed by us; however, if
a management member has three full years of service with the
Partnership following the completion of an initial public
offering of the
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Partnership, such management member may retire at age 62
and will be entitled to permanently retain all of his or her
units whether or not they have vested pursuant to the vesting
schedule described above. Units forfeited will be either retired
or reissued to others (with a catchup payment provision);
retired units will increase the unit values of all other units
on a pro rata basis. The following executive officers received
the following grants of this category of override units:
Mr. Lipinski (219,378), Mr. Riemann (75,000),
Mr. Rens (48,750), Mr. Haugen (13,125),
Mr. Jernigan (11,250), Mr. Gross (22,500),
Mr. Vick (45,000), Mr. Swanberg (11,250) and
Mr. Daly (18,750).
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The override units granted to management are entitled to 15% of
all distributions made by Coffeyville Acquisition III LLC.
All vested and unvested override units are entitled to
distributions. To the extent that at any time not all override
units have yet been granted, the override units that have been
granted will be entitled to the full 15% of all distributions
(e.g., if only 90% of the override units have been granted, the
holders of these 90% are entitled to 15% of all distributions).
A portion of the override units may be granted in the future to
new members of management. A catch up payment will be made to
new members of management who receive units at a time when the
current unit value has increased from the initial unit value.
The value of the common units and override units in Coffeyville
Acquisition III LLC depends on the ability of the
Partnerships managing general partner to make
distributions. The managing general partner will not receive any
distributions from the Partnership until the Partnerships
aggregate adjusted operating surplus through December 31,
2009 has been distributed. Based on the Partnerships
current projections, the Partnership believes that the executive
officers will not begin to receive distributions on their common
and override units until after December 31, 2010.
Adjustments to Capital Accounts;
Distributions.
Each of the executive officers has
a capital account under which his balance is increased or
decreased, as applicable, to reflect his allocable share of net
income and gross income of Coffeyville Acquisition III LLC,
the capital that the executive officer contributed,
distributions paid to such executive officer and his allocable
share of net loss and items of gross deduction.
Override units owned by the executive officers do not
participate in distributions under the Coffeyville
Acquisition III LLC limited liability company agreement
until the Current Value is at least equal to the
Initial Price (as these terms are defined in the
Coffeyville Acquisition III LLC limited liability company
agreement). Coffeyville Acquisition III LLC may make
distributions to its members to the extent that the cash
available to it is in excess of the business reasonably
anticipated needs. Distributions are generally made to
members capital accounts in proportion to the number of
units each member holds. Distributions in respect of override
units, however, will be reduced until the total reductions in
proposed distributions in respect of the override units equals
the aggregate capital contributions of all members.
Other Provisions Relating to Coffeyville Acquisition III
LLC Units.
The executive officers are subject to
transfer restrictions on their Coffeyville Acquisition III
LLC units, although they may make certain transfers of their
units for estate planning purposes.
Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan I) and
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
II)
The following is a summary of the material terms of the
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
I), or the Phantom Unit Plan I, and the Coffeyville
Resources LLC Phantom Unit Appreciation Plan (Plan II), or the
Phantom Unit Plan II, as they relate to our named executive
officers. Payments under the Phantom Unit Plan I are tied to
distributions made by Coffeyville Acquisition LLC, and payments
under the Phantom Unit Plan II are tied to distributions
made by Coffeyville Acquisition II LLC. We refer to the
Phantom Unit Plan I and Phantom Unit Plan II collectively
as the Phantom Unit Plans.
General.
The Phantom Unit Plan I and Phantom
Unit Plan II are administered by the compensation
committees of the boards of directors of Coffeyville Acquisition
LLC and Coffeyville Acquisition II
198
LLC, as applicable. The Phantom Unit Plans provide for two
classes of interests: phantom service points and phantom
performance points (collectively referred to as phantom points).
Holders of the phantom service points and phantom performance
points have the opportunity to receive a cash payment when
distributions are made pursuant to the LLC Agreements in respect
of operating units and value units, respectively. The phantom
points represent a contractual right to receive a payment when
payment is made in respect of certain profits interests in
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, as applicable.
Phantom points have been granted under each of the Phantom Unit
Plans to our named executive officers in the following amounts:
Mr. Lipinski (1,368,571 phantom service points and
1,368,571 phantom performance points, which represents
approximately 14% of the total phantom points awarded),
Mr. Riemann (596,133 phantom service points and 596,133
phantom performance points, which represents approximately 6% of
the total phantom points awarded), Mr. Rens
(495,238 phantom service points and 495,238 phantom
performance points, which represents approximately 5% of the
total phantom points awarded), Mr. Haugen (495,238 phantom
service points and 495,238 phantom performance points,
which represents approximately 5% of the total phantom points
awarded) and Mr. Daly (552,381 phantom service points and
552,381 phantom performance points, which represents
approximately 6% of the total phantom points awarded).
If all of the shares of common stock of our company held by
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC were sold at $24.92 per share, which was the closing price
of our common stock on June 16, 2008, and cash was
distributed to members pursuant to the LLC Agreement and the
Coffeyville Acquisition II LLC Agreement, our named
executive officers would receive a cash payment in respect of
their phantom points in the following amounts: Mr. Lipinski
($8.8 million), Mr. Riemann ($3.8 million),
Mr. Rens ($3.2 million), Mr. Haugen
($3.2 million) and Mr. Daly ($3.5 million). The
compensation committees of the boards of directors of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC have authority to make additional awards of phantom points
under the Phantom Unit Plans.
Assuming the underwriters option to purchase additional
shares is not exercised, if all of the shares of common stock of
our Company to be sold in this offering by Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC were
sold at $24.92 per share, which was the price of our common
stock on June 16, 2008, each of our named executive
officers will receive a cash payment in respect of their phantom
points in the following approximate amounts: Mr. Lipinski
($0.5 million), Mr. Riemann ($0.2 million),
Mr. Rens ($0.2 million), Mr. Haugen
($0.2 million), and Mr. Daly ($0.2 million).
Phantom Point Payments.
Payments in respect of
phantom service points will be made within 30 days from the
date distributions are made pursuant to the LLC Agreements in
respect of operating units. Cash payments in respect of phantom
performance points will be made within 30 days from the
date distributions are made pursuant to the LLC Agreements in
respect of value units (i.e., not until the Current
Value is at least two times the Initial Price
(as such terms are defined in the LLC Agreements), with full
participation occurring when the Current Value is four times the
Initial Price and pro rata distributions when the Current Value
is between two and four times the Initial Price). There is also
a
catch-up
provision with respect to phantom performance points for which
no cash payment was made because no distribution pursuant to the
LLC Agreements was made with respect to value units.
Other Provisions Relating to the Phantom
Points.
The boards of directors of Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC may, at
any time or from time to time, amend or terminate the Phantom
Unit Plans. If a participants employment is terminated
prior to an Exit Event (as such term is defined in
the LLC Agreements), all of the participants phantom
points are forfeited. Phantom points are generally
non-transferable (except by will or the laws of descent and
distribution). If payment to a participant in respect of his
phantom points would result in the application of the excise tax
imposed under Section 4999 of the Internal Revenue Code of
1986, as amended, then the payment will be cut back
only if that reduction would be more beneficial to the
participant on an after-tax basis than if there were no
reduction.
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Outstanding
Equity Awards at 2007 Fiscal Year-End
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Stock Awards
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Number of Shares
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Market Value of
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or Units of Stock
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Shares or Units of
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That Have Not
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Stock That Have Not
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Name
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Vested (#)(1)(2)
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Vested ($)(3)
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John J. Lipinski
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118,431.7
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(4)
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$
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6,139,499
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315,818.5
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(5)
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$
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16,372,031
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36,246.0
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(6)
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$
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1,878,993
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72,483.0
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(7)
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$
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2,366,570
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|
|
118,431.7
|
(8)
|
|
$
|
6,139,499
|
|
|
|
|
315,818.5
|
(9)
|
|
$
|
16,372,031
|
|
|
|
|
36,246.0
|
(10)
|
|
$
|
1,878,993
|
|
|
|
|
72,483
|
(11)
|
|
$
|
2,366,570
|
|
|
|
|
1,368,571
|
(12)
|
|
$
|
1,241,568
|
|
|
|
|
1,368,571
|
(13)
|
|
$
|
2,483,136
|
|
|
|
|
1,368,571
|
(14)
|
|
$
|
1,241,568
|
|
|
|
|
1,368,571
|
(15)
|
|
$
|
2,483,136
|
|
James T. Rens
|
|
|
26,986.9
|
(16)
|
|
$
|
1,399,001
|
|
|
|
|
71,965.5
|
(17)
|
|
$
|
3,730,692
|
|
|
|
|
26,986.9
|
(18)
|
|
$
|
1,399,001
|
|
|
|
|
71,965.5
|
(19)
|
|
$
|
3,730,692
|
|
|
|
|
495,238
|
(20)
|
|
$
|
449,271
|
|
|
|
|
495,238
|
(21)
|
|
$
|
898,569
|
|
|
|
|
495,238
|
(22)
|
|
$
|
449,271
|
|
|
|
|
495,238
|
(23)
|
|
$
|
898,569
|
|
Stanley A. Riemann
|
|
|
52,569.4
|
(24)
|
|
$
|
2,725,198
|
|
|
|
|
140,185.5
|
(25)
|
|
$
|
7,267,216
|
|
|
|
|
52,569.4
|
(26)
|
|
$
|
2,725,198
|
|
|
|
|
140,185.5
|
(27)
|
|
$
|
7,267,216
|
|
|
|
|
596,133
|
(28)
|
|
$
|
540,821
|
|
|
|
|
596,133
|
(29)
|
|
$
|
1,081,616
|
|
|
|
|
596,133
|
(30)
|
|
$
|
540,821
|
|
|
|
|
596,133
|
(31)
|
|
$
|
1,081,616
|
|
Robert W. Haugen
|
|
|
26,986.9
|
(32)
|
|
$
|
1,399,001
|
|
|
|
|
71,965.5
|
(33)
|
|
$
|
3,730,692
|
|
|
|
|
26,986.9
|
(34)
|
|
$
|
1,399,001
|
|
|
|
|
71,965.5
|
(35)
|
|
$
|
3,730,692
|
|
|
|
|
495,238
|
(36)
|
|
$
|
449,271
|
|
|
|
|
495,238
|
(37)
|
|
$
|
898,569
|
|
|
|
|
495,238
|
(38)
|
|
$
|
449,271
|
|
|
|
|
495,238
|
(39)
|
|
$
|
898,569
|
|
Daniel J. Daly, Jr.
|
|
|
19,462.9
|
(40)
|
|
$
|
1,008,957
|
|
|
|
|
51,900.5
|
(41)
|
|
$
|
2,690,522
|
|
|
|
|
19,462.9
|
(42)
|
|
$
|
1,008,957
|
|
|
|
|
51,900.5
|
(43)
|
|
$
|
2,690,522
|
|
|
|
|
552,381
|
(44)
|
|
$
|
501,111
|
|
|
|
|
552,381
|
(45)
|
|
$
|
1,002,249
|
|
|
|
|
552,381
|
(46)
|
|
$
|
501,111
|
|
|
|
|
552,381
|
(47)
|
|
$
|
1,002,249
|
|
200
|
|
|
(1)
|
|
The profits interests in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC generally vest as follows:
operating units generally become non-forfeitable in 25% annual
increments beginning on the second anniversary of the date of
grant, and value units are generally forfeitable upon
termination of employment. The profits interests are more fully
described above under Executive Officers
Interests in Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC.
|
|
(2)
|
|
The phantom points granted pursuant to the Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan I) and
the Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan II) are generally forfeitable upon termination of
employment. The phantom points are more fully described above
under Coffeyville Resources, LLC Phantom Unit
Appreciation Plan (Plan I) and Coffeyville Resources, LLC
Phantom Unit Appreciation Plan (Plan II).
|
|
(3)
|
|
The dollar amount shown reflects the fair value as of
December 31, 2007, based upon an independent third-party
valuation performed as of December 31, 2007 using the
December 31, 2007 CVR Energy common stock closing price on
the NYSE to determine the equity value of CVR Energy.
Assumptions used in the calculation of these amounts are
included in footnote 3 to the Companys audited financial
statements for the year ended December 31, 2007 included
elsewhere in this prospectus.
|
|
(4)
|
|
Represents 118,431.7 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
These operating units have been transferred to trusts for the
benefit of members of Mr. Lipinskis family.
|
|
(5)
|
|
Represents 315,818.5 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on June 24, 2005.
These value units have been transferred to trusts for the
benefit of members of Mr. Lipinskis family.
|
|
(6)
|
|
Represents 36,246.0 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on December 29,
2006. These operating units have been transferred to trusts for
the benefit of members of Mr. Lipinskis family.
|
|
(7)
|
|
Represents 72,483.0 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on December 29, 2006.
These value units have been transferred to trusts for the
benefit of members of Mr. Lipinskis family.
|
|
(8)
|
|
Represents 118,431.7 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
December 29, 2006. These operating units have been
transferred to trusts for the benefit of members of
Mr. Lipinskis family.
|
|
(9)
|
|
Represents 315,818.5 value units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
December 29, 2006. These value units have been transferred
to trusts for the benefit of members of Mr. Lipinskis
family.
|
|
(10)
|
|
Represents 36,246.0 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
December 29, 2006. These operating units have been
transferred to trusts for the benefit of members of
Mr. Lipinskis family.
|
|
(11)
|
|
Represents 72,483 value units in Coffeyville Acquisition II
LLC deemed to be granted to the executive on December 29,
2006. These value units have been transferred to trusts for the
benefit of members of Mr. Lipinskis family.
|
|
(12)
|
|
Represents 1,368,571 phantom service points under the Phantom
Unit Plan I granted to the executive on December 11, 2006.
|
|
(13)
|
|
Represents 1,368,571 phantom performance points under the
Phantom Unit Plan I granted to the executive on
December 11, 2006.
|
|
(14)
|
|
Represents 1,368,571 phantom service points under the Phantom
Unit Plan II granted to the executive on December 11,
2006.
|
|
(15)
|
|
Represents 1,368,571 phantom performance points under the
Phantom Unit Plan II granted to the executive on
December 11, 2006.
|
201
|
|
|
(16)
|
|
Represents 26,986.9 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(17)
|
|
Represents 71,965.5 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on June 24, 2005.
|
|
(18)
|
|
Represents 26,986.9 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(19)
|
|
Represents 71,965.5 value units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(20)
|
|
Represents 495,238 phantom service points under the Phantom Unit
Plan I granted to the executive on December 11, 2006.
|
|
(21)
|
|
Represents 495,238 phantom performance points under the Phantom
Unit Plan I granted to the executive on December 11, 2006.
|
|
(22)
|
|
Represents 495,238 phantom service points under the Phantom Unit
Plan II granted to the executive on December 11, 2006.
|
|
(23)
|
|
Represents 495,238 phantom performance points under the Phantom
Unit Plan II granted to the executive on December 11,
2006.
|
|
(24)
|
|
Represents 52,569.4 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(25)
|
|
Represents 140,185.5 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on June 24, 2005.
|
|
(26)
|
|
Represents 52,569.4 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(27)
|
|
Represents 140,185.5 value units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(28)
|
|
Represents 596,133 phantom service points under the Phantom Unit
Plan I granted to the executive on December 11, 2006.
|
|
(29)
|
|
Represents 596,133 phantom performance points under the Phantom
Unit Plan I granted to the executive on December 11, 2006.
|
|
(30)
|
|
Represents 596,133 phantom service points under the Phantom Unit
Plan II granted to the executive on December 11, 2006.
|
|
(31)
|
|
Represents 596,133 phantom performance points under the Phantom
Unit Plan II granted to the executive on December 11,
2006.
|
|
(32)
|
|
Represents 26,986.9 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(33)
|
|
Represents 71,965.5 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on June 24, 2005.
|
|
(34)
|
|
Represents 26,986.9 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(35)
|
|
Represents 71,965.5 value units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(36)
|
|
Represents 495,238 phantom service points under the Phantom Unit
Plan I granted to the executive on December 11, 2006.
|
|
(37)
|
|
Represents 495,238 phantom performance points under the Phantom
Unit Plan I granted to the executive on December 11, 2006.
|
|
(38)
|
|
Represents 495,238 phantom service points under the Phantom Unit
Plan II granted to the executive on December 11, 2006.
|
202
|
|
|
(39)
|
|
Represents 495,238 phantom performance points under the Phantom
Unit Plan II granted to the executive on December 11,
2006.
|
|
(40)
|
|
Represents 19,462.9 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(41)
|
|
Represents 51,900.5 value units in Coffeyville Acquisition LLC
deemed to be granted to the executive on June 24, 2005.
|
|
(42)
|
|
Represents 19,462.9 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(43)
|
|
Represents 51,900.5 value units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(44)
|
|
Represents 552,381 phantom service points under the Phantom Unit
Plan I granted to the executive on December 11, 2006.
|
|
(45)
|
|
Represents 552,381 phantom performance points under the Phantom
Unit Plan I granted to the executive on December 11, 2006.
|
|
(46)
|
|
Represents 552,381 phantom service points under the Phantom Unit
Plan II granted to the executive on December 11, 2006.
|
|
(47)
|
|
Represents 552,381 phantom performance points under the Phantom
Unit Plan II granted to the executive on December 11,
2006.
|
Equity Awards at
2007 Fiscal Year-End That Have Vested
|
|
|
|
|
|
|
|
|
|
|
Stock Awards
|
|
|
|
Number of
|
|
|
|
|
|
|
Shares Acquired
|
|
|
Value Realized
|
|
|
|
on Vesting
|
|
|
on Vesting
|
|
Name
|
|
(#)(1)(2)(3)
|
|
|
($)(4)
|
|
|
John J. Lipinski
|
|
|
39,477.3
|
(5)
|
|
$
|
1,516,323
|
|
|
|
|
39,477.3
|
(6)
|
|
$
|
1,516,323
|
|
|
|
|
53,921
|
(7)
|
|
$
|
1,078
|
|
James T. Rens
|
|
|
8,995.6
|
(8)
|
|
$
|
345,521
|
|
|
|
|
8,995.6
|
(9)
|
|
$
|
345,521
|
|
|
|
|
10,066
|
(10)
|
|
$
|
201
|
|
Stanley A. Riemann
|
|
|
17,523.1
|
(11)
|
|
$
|
673,062
|
|
|
|
|
17,523.1
|
(12)
|
|
$
|
673,062
|
|
|
|
|
19,650
|
(13)
|
|
$
|
393
|
|
Robert W. Haugen
|
|
|
8,995.6
|
(14)
|
|
$
|
345,521
|
|
|
|
|
8,995.6
|
(15)
|
|
$
|
345,521
|
|
|
|
|
10,066
|
(16)
|
|
$
|
201
|
|
Daniel J. Daly, Jr.
|
|
|
6,487.6
|
(17)
|
|
$
|
249,189
|
|
|
|
|
6,487.6
|
(18)
|
|
$
|
249,189
|
|
|
|
|
7,190
|
(19)
|
|
$
|
144
|
|
|
|
|
(1)
|
|
The profits interests in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC generally vest as follows:
operating units generally become non-forfeitable in 25% annual
increments beginning on the second anniversary of the date of
grant, and value units are generally forfeitable upon
termination of employment. The profits interests are more fully
described above under Executive Officers
Interests in Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC.
|
|
(2)
|
|
The profits interests in Coffeyville Acquisition III LLC
described in this table were granted on October 24, 2007
and automatically vested on the date of grant, as more fully
described above under Executive Officers
Interests in Coffeyville Acquisition III LLC.
|
203
|
|
|
(3)
|
|
The phantom points granted pursuant to the Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan I) and
the Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan II) are generally forfeitable upon termination of
employment. The phantom points are more fully described above
under Coffeyville Resources, LLC Phantom Unit
Appreciation Plan (Plan I) and Coffeyville Resources, LLC
Phantom Unit Appreciation Plan (Plan II).
|
|
(4)
|
|
The dollar amounts shown are based on a valuation determined for
purposes of SFAS 123(R) at the relevant vesting date of the
respective override units.
|
|
(5)
|
|
Represents 39,477.3 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
These operating units have been transferred to trusts for the
benefit of members of Mr. Lipinskis family.
|
|
(6)
|
|
Represents 39,477.3 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005. These operating units have been transferred
to trusts for the benefit of members of Mr. Lipinskis
family.
|
|
(7)
|
|
Represents profits interests in Coffeyville Acquisition III
LLC (53,921 override units) granted to the executive on
October 24, 2007.
|
|
(8)
|
|
Represents 8,995.6 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(9)
|
|
Represents 8,995.6 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(10)
|
|
Represents profits interests in Coffeyville Acquisition III
LLC (10,066 override units) granted to the executive on
October 24, 2007.
|
|
(11)
|
|
Represents 17,523.1 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(12)
|
|
Represents 17,523.1 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(13)
|
|
Represents profits interests in Coffeyville Acquisition III
LLC (19,650 override units) granted to the executive on
October 24, 2007.
|
|
(14)
|
|
Represents 8,995.6 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(15)
|
|
Represents 8,995.6 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(16)
|
|
Represents profits interests in Coffeyville Acquisition III
LLC (10,066 override units) granted to the executive on
October 24, 2007.
|
|
(17)
|
|
Represents 6,487.6 operating units in Coffeyville Acquisition
LLC deemed to be granted to the executive on June 24, 2005.
|
|
(18)
|
|
Represents 6,487.6 operating units in Coffeyville
Acquisition II LLC deemed to be granted to the executive on
June 24, 2005.
|
|
(19)
|
|
Represents profits interests in Coffeyville Acquisition III
LLC (7,190 override units) granted to the executive on
October 24, 2007.
|
Potential
Payments Upon Termination or Change of Control
Under the terms of their respective employment agreements, the
named executive officers may be entitled to severance and other
benefits following the termination of their employment. These
benefits are summarized below. The amounts of potential
post-employment payments assume that the triggering event took
place on December 31, 2007.
If Mr. Lipinskis employment is terminated either by
CVR Energy without cause and other than for disability or by
Mr. Lipinski for good reason (as these terms are defined in
Mr. Lipinskis
204
employment agreement), then Mr. Lipinski is entitled to
receive as severance (a) salary continuation for
36 months and (b) the continuation of medical benefits
for thirty-six months at active-employee rates or until such
time as Mr. Lipinski becomes eligible for medical benefits
from a subsequent employer. The estimated total amounts of these
payments are set forth in the table below. As a condition to
receiving the salary continuation and continuation of medical
benefits, Mr. Lipinski must (a) execute, deliver and
not revoke a general release of claims and (b) abide by
restrictive covenants as detailed below. If
Mr. Lipinskis employment is terminated as a result of
his disability, then in addition to any payments to be made to
Mr. Lipinski under disability plan(s), Mr. Lipinski is
entitled to supplemental disability payments equal to, in the
aggregate, Mr. Lipinskis base salary as in effect
immediately before his disability (the estimated total amount of
this payment is set forth in the table below). Such supplemental
disability payments will be made in installments for a period of
36 months from the date of disability. If
Mr. Lipinskis employment is terminated at any time by
reason of his death, then Mr. Lipinskis beneficiary
(or his estate) will be paid the base salary Mr. Lipinski
would have received had he remained employed through the
remaining term of his contract. Notwithstanding the foregoing,
CVR Energy may, at its option, purchase insurance to cover the
obligations with respect to either Mr. Lipinskis
supplemental disability payments or the payments due to
Mr. Lipinskis beneficiary or estate by reason of his
death. Mr. Lipinski will be required to cooperate in
obtaining such insurance. If any payments or distributions due
to Mr. Lipinski would be subject to the excise tax imposed
under Section 4999 of the Internal Revenue Code of 1986, as
amended, then such payments or distributions will be cut
back only if that reduction would be more beneficial to
him on an after-tax basis than if there were no reduction.
The agreement requires Mr. Lipinski to abide by a perpetual
restrictive covenant relating to non-disclosure. The agreement
also includes covenants relating to non-solicitation and
non-competition during Mr. Lipinskis employment term
and, following the end of term, for as long as he is receiving
severance or supplemental disability payments or one year if he
is receiving none.
If the employment of Mr. Riemann, Mr. Rens,
Mr. Haugen or Mr. Daly is terminated either by CVR
Energy without cause and other than for disability or by the
executive officer for good reason (as such terms are defined in
the respective employment agreements), then the executive
officer is entitled to receive as severance (a) salary
continuation for 12 months (18 months for
Mr. Riemann) and (b) the continuation of medical
benefits for 12 months (18 months for
Mr. Riemann) at active-employee rates or until such time as
the executive officer becomes eligible for medical benefits from
a subsequent employer. The amount of these payments is set forth
in the table below. As a condition to receiving the salary, the
executives must (a) execute, deliver and not revoke a
general release of claims and (b) abide by restrictive
covenants as detailed below. The agreements provide that if any
payments or distributions due to an executive officer would be
subject to the excise tax imposed under Section 4999 of the
Internal Revenue Code, as amended, then such payments or
distributions will be cut back only if that reduction would be
more beneficial to the executive officer on an after-tax basis
than if there were no reduction.
The agreements require each of the executive officers to abide
by a perpetual restrictive covenant relating to non-disclosure.
The agreements also include covenants relating to
non-solicitation and non-competition during their employment
and, following termination of employment, for one year (for
Mr. Riemann, the applicable period is during his employment
and, following termination of employment, for as long as he is
receiving severance, or one year if he is receiving none).
205
Below is a table setting forth the estimated aggregate amount of
the payments discussed above assuming a December 31, 2007
termination date (and, where applicable, no offset due to
eligibility to receive medical benefits from a subsequent
employer). The table assumes that the executive officers
termination was by CVR Energy without cause or by the executive
officers for good reason, and in the case of Mr. Lipinski
also provides information assuming his termination was due to
his disability.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Dollar
|
|
|
|
Total Severance
|
|
|
Value of Medical
|
|
Name
|
|
Payments
|
|
|
Benefits
|
|
|
John J. Lipinski (severance if terminated without cause or
resigns for good reason)
|
|
$
|
1,950,000
|
|
|
$
|
25,106
|
|
John J. Lipinski (supplemental disability payments if terminated
due to disability)
|
|
$
|
650,000
|
|
|
|
|
|
Stanley A. Riemann (severance if terminated without cause or
resigns for good reason)
|
|
$
|
525,000
|
|
|
$
|
12,553
|
|
James T. Rens (severance if terminated without cause or resigns
for good reason)
|
|
$
|
250,000
|
|
|
$
|
11,998
|
|
Robert W. Haugen (severance if terminated without cause or
resigns for good reason)
|
|
$
|
275,000
|
|
|
$
|
11,998
|
|
Daniel J. Daly, Jr. (severance if terminated without cause or
resigns for good reason)
|
|
$
|
215,000
|
|
|
$
|
3,899
|
|
Equity
Compensation Plan Information
The following table shows the total number of outstanding
options and shares available for future issuances under our
equity compensation plans as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Number of Securities
|
|
|
|
Securities to Be
|
|
|
|
|
|
Remaining Available
|
|
|
|
Issued Upon
|
|
|
Weighted-Average
|
|
|
for Future Issuance
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
Under Equity
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Compensation Plans
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
(Excluding Securities
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
Reflected in Column
(a)
|
|
|
Equity Compensation Plans Approved by Security Holders
|
|
|
18,900
|
|
|
$
|
21.61
|
|
|
|
7,463,600
|
|
Equity Compensation Plans Not Approved by Security Holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
18,900
|
|
|
$
|
21.61
|
|
|
|
7,463,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
206
Director
Compensation for 2007
The following table provides compensation information for the
year ended December 31, 2007 for each non-management
director of our board.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earned or
|
|
|
Stock
|
|
|
Option
|
|
|
All Other
|
|
|
|
|
Name
|
|
Paid in Cash
|
|
|
Awards(1)(2)
|
|
|
Awards(3)(4)(5)
|
|
|
Compensation
|
|
|
Total
|
|
|
Wesley K. Clark*
|
|
$
|
60,000
|
|
|
|
|
|
|
|
|
|
|
$
|
449,290
|
(6)
|
|
$
|
509,290
|
|
Regis B. Lippert
|
|
$
|
35,000
|
|
|
$
|
11,885
|
|
|
$
|
7,737
|
|
|
|
|
|
|
$
|
54,662
|
|
Mark E. Tomkins
|
|
$
|
75,000
|
|
|
$
|
29,714
|
|
|
$
|
7,737
|
|
|
|
|
|
|
$
|
112,451
|
|
Scott L. Lebovitz, George E. Matelich, Stanley de J. Osborne and
Kenneth A. Pontarelli
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Wesley K. Clark, who was first elected to the board of
Coffeyville Acquisition LLC in 2006, advised the board that due
to his various outside interests and responsibilities he did not
want to be nominated for reelection. Steve A. Nordaker replaced
Mr. Clark on our board effective June 6, 2008.
|
|
(1)
|
|
Mr. Lippert and Mr. Tomkins were awarded 5,000 and
12,500 shares of restricted stock, respectively, on
October 22, 2007. The dollar amounts in the table reflect
the dollar amounts recognized for financial statement reporting
purposes for the fiscal year ended December 31, 2007 in
accordance with SFAS 123(R). Assumptions used in these
amounts are included in footnote 3 to the Companys audited
financial statements for the year ended December 31, 2007
included elsewhere in this prospectus.
|
|
(2)
|
|
The grant date fair value of stock awards granted during 2007,
calculated in accordance with SFAS 123(R), was $104,400 for
Mr. Lippert and $261,000 for Mr. Tomkins. Assumptions
used in these amounts are included in footnote 3 to the
Companys audited financial statements for the year ended
December 31, 2007 included elsewhere in this prospectus.
|
|
(3)
|
|
Mr. Lippert and Mr. Tomkins were awarded stock options
in respect of (x) 5,150 shares each on
October 22, 2007 and (y) 4,300 shares each on
December 21, 2007. The amounts in the table reflect the
dollar amount recognized for financial statement reporting
purposes for the fiscal year ended December 31, 2007, in
accordance with SFAS 123(R). Assumptions used in these
amounts are included in footnote 3 to the Companys audited
financial statements for the year ended December 31, 2007
included elsewhere in this prospectus.
|
|
(4)
|
|
The grant date fair value of Mr. Lipperts and
Mr. Tomkins option awards granted during 2007,
calculated in accordance with FAS 123(R), was $117,881 for
each director. Assumptions used in these amounts are included in
footnote 3 to the Companys audited financial statements
for the year ended December 31, 2007 included elsewhere in
this prospectus.
|
|
(5)
|
|
The aggregate number of shares subject to option awards
outstanding on December 31, 2007 was 9,450 for each of
Messrs. Lippert and Tomkins.
|
|
(6)
|
|
Mr. Clark was awarded 244,038 phantom service points and
244,038 phantom performance points under the Coffeyville
Resources, LLC Phantom Unit Plan (Plan I) in September 2005
for his services as a director. Collectively,
Mr. 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 was performed as of December 31, 2007
using the December 31, 2007 CVR Energy common stock closing
price on the NYSE to determine the equity value of CVR Energy.
Assumptions used in the calculation of these amounts are
included in footnote 3 to the Companys audited financial
statements for the year ended December 31, 2007 included
elsewhere in this prospectus. The phantom points are
|
207
|
|
|
|
|
more fully described below under Coffeyville
Resources, LLC Phantom Unit Appreciation Plan (Plan I) and
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
II).
|
Non-employee directors who do not work principally for entities
affiliated with us were entitled to receive an annual retainer
of $60,000 for 2007. In addition, all directors are reimbursed
for travel expenses and other out-of-pocket costs incurred in
connection with their attendance at meetings. Effective
January 1, 2007, Mark Tomkins joined our board of
directors. Mr. Tomkins was elected as the chairman of the
audit committee and in that role he receives an additional
annual retainer of $15,000. Messrs. Lebovitz, Matelich,
Osborne and Pontarelli received no compensation in respect of
their service as directors in 2007.
In addition to the annual retainer described above, we granted
to each of Mr. Tomkins and Mr. Lippert options to
purchase 5,150 shares of CVR Energy with an exercise price
equal to the initial public offering price ($19.00) on
October 22, 2007. These options generally vest in one-third
annual increments beginning on the first anniversary of the date
of grant. We also granted 12,500 restricted shares of CVR Energy
to Mr. Tomkins and 5,000 restricted shares of CVR Energy to
Mr. Lippert on October 24, 2007. These shares of
restricted stock generally vest in one-third annual increments
beginning on the first anniversary of the date of grant,
although the holder has the right to vote the shares whether or
not they have vested. We also granted to each of
Mr. Tomkins and Mr. Lippert options to purchase
4,300 shares of CVR Energy with an exercise price of $24.73
on December 21, 2007.
In connection with his election to our board of directors, we
granted Mr. Nordaker options to purchase 4,350 shares
of CVR Energy stock with an exercise price of $24.96 on
June 10, 2008.
All grants were made pursuant to our 2007 Long Term Incentive
Plan.
208
PRINCIPAL AND
SELLING STOCKHOLDERS
The following table presents information regarding beneficial
ownership of our common stock by:
|
|
|
|
|
each of our directors;
|
|
|
|
each of our named executive officers;
|
|
|
|
each stockholder known by us to beneficially hold five percent
or more of our common stock;
|
|
|
|
all of our executive officers and directors as a group; and
|
|
|
|
all selling stockholders.
|
Beneficial ownership is determined under the rules of the SEC
and generally includes voting or investment power with respect
to securities. Unless indicated below, to our knowledge, the
persons and entities named in the table have sole voting and
sole investment power with respect to all shares beneficially
owned, subject to community property laws where applicable.
Shares of common stock subject to options that are currently
exercisable or exercisable within 60 days of the date of
this prospectus are deemed to be outstanding and to be
beneficially owned by the person holding such options for the
purpose of computing the percentage ownership of that person but
are not treated as outstanding for the purpose of computing the
percentage ownership of any other person. Except as otherwise
indicated, the business address for each of our beneficial
owners is
c/o CVR
Energy, Inc., 2277 Plaza Drive, Suite 500, Sugar Land,
Texas 77479.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Beneficially
|
|
|
|
Shares Beneficially Owned
|
|
|
Number of
|
|
|
Owned
|
|
Beneficial Owner
|
|
prior to the offering
|
|
|
Shares
|
|
|
after the
offering
|
|
Name and Address
|
|
Number
|
|
|
Percent
|
|
|
Offered
|
|
|
Number
|
|
|
Percent
|
|
|
Coffeyville Acquisition LLC(1)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
Kelso Investment Associates VII, L.P.(1)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
KEP Fertilizer, LLC(1)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
320 Park Avenue, 24th Floor
New York, New York 10022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coffeyville Acquisition II LLC(2)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
The Goldman Sachs Group, Inc.(2)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
85 Broad Street
New York, New York 10004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John J. Lipinski(3)
|
|
|
247,471
|
|
|
|
|
*
|
|
|
45,000
|
|
|
|
202,471
|
|
|
|
|
*
|
Stanley A. Riemann(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James T. Rens(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert W. Haugen(6)
|
|
|
5,000
|
|
|
|
|
*
|
|
|
|
|
|
|
5,000
|
|
|
|
|
*
|
Daniel J. Daly, Jr.(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Scott L. Lebovitz(2)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
Regis B. Lippert(8)
|
|
|
7,500
|
|
|
|
|
*
|
|
|
|
|
|
|
7,500
|
|
|
|
|
*
|
George E. Matelich(1)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
Steve A. Nordaker(9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stanley de J. Osborne(1)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
Kenneth A. Pontarelli(2)
|
|
|
31,433,360
|
|
|
|
36.5
|
%
|
|
|
4,977,500
|
|
|
|
26,455,860
|
|
|
|
30.7
|
%
|
Mark Tomkins(10)
|
|
|
12,500
|
|
|
|
|
*
|
|
|
|
|
|
|
12,500
|
|
|
|
|
*
|
All directors and executive officers, as a group
(16 persons)(11)
|
|
|
63,145,691
|
|
|
|
73.3
|
%
|
|
|
10,000,000
|
|
|
|
53,145,691
|
|
|
|
61.7
|
%
|
|
|
|
|
|
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC have granted the underwriters the option to purchase from
them, on a pro rata basis, an aggregate of 1,500,000 additional
shares. If the option to purchase additional shares were
exercised in full, after the offering Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC would each own
25,705,860 shares, or 29.8%, of our common stock, and all
of our directors and executive officers, as a group, would own
51,645,691 shares, or 60.0%, of our common stock.
|
|
*
|
|
Less than 1%.
|
209
|
|
|
(1)
|
|
Coffeyville Acquisition LLC directly owns 31,433,360 shares
of common stock. Kelso Investment Associates VII, L.P.
(KIA VII), a Delaware limited partnership, owns a
number of common units in Coffeyville Acquisition LLC that
corresponds to 24,557,883 shares of common stock, and KEP
Fertilizer, LLC (KEP Fertilizer), a Delaware limited
liability company, owns a number of common units in Coffeyville
Acquisition LLC that corresponds to 6,081,000 shares of
common stock. The Kelso Funds may be deemed to beneficially own
indirectly, in the aggregate, all of the common stock of the
Company owned by Coffeyville Acquisition LLC because the Kelso
Funds control Coffeyville Acquisition LLC and have the power to
vote or dispose of the common stock of the Company owned by
Coffeyville Acquisition LLC. KIA VII and KEP Fertilizer, due to
their common control, could be deemed to beneficially own each
of the others shares but each disclaims such beneficial
ownership. Messrs. Nickell, Wall, Matelich, Goldberg,
Bynum, Wahrhaftig, Berney, Loverro, Connors, Osborne and Moore
may be deemed to share beneficial ownership of shares of common
stock owned of record or beneficially owned by KIA VII, KEP
Fertilizer and Coffeyville Acquisition LLC by virtue of their
status as managing members of KEP Fertilizer and of Kelso GP
VII, LLC, a Delaware limited liability company, the principal
business of which is serving as the general partner of Kelso GP
VII, L.P., a Delaware limited partnership, the principal
business of which is serving as the general partner of KIA VII.
Each of Messrs. Nickell, Wall, Matelich, Goldberg, Bynum,
Wahrhaftig, Berney, Loverro, Connors, Osborne and Moore share
investment and voting power with respect to the ownership
interests owned by KIA VII, KEP Fertilizer and Coffeyville
Acquisition LLC but disclaim beneficial ownership of such
interests.
|
|
(2)
|
|
Coffeyville Acquisition II LLC directly owns
31,433,360 shares of common stock. GS Capital Partners V
Fund, L.P., GS Capital Partners V Offshore Fund, L.P., GS
Capital Partners V GmbH & Co. KG and GS Capital
Partners V Institutional, L.P. (collectively, the Goldman
Sachs Funds) are members of Coffeyville
Acquisition II LLC and own common units of Coffeyville
Acquisition II LLC. The Goldman Sachs Funds common
units in Coffeyville Acquisition II LLC correspond to
31,125,918 shares of common stock. The Goldman Sachs Group,
Inc. and Goldman, Sachs & Co. may be deemed to
beneficially own indirectly, in the aggregate, all of the common
stock owned by Coffeyville Acquisition II LLC through the
Goldman Sachs Funds because (i) affiliates of Goldman,
Sachs & Co. and The Goldman Sachs Group, Inc. are the
general partner, managing general partner, managing partner,
managing member or member of the Goldman Sachs Funds and
(ii) the Goldman Sachs Funds control Coffeyville
Acquisition II LLC and have the power to vote or dispose of
the common stock of the Company owned by Coffeyville
Acquisition II LLC. Goldman, Sachs & Co. is a
direct and indirect wholly owned subsidiary of The Goldman Sachs
Group, Inc. Goldman, Sachs & Co. is the investment
manager of certain of the Goldman Sachs Funds. Shares that may
be deemed to be beneficially owned by the Goldman Sachs Funds
consist of: (1) 16,389,665 shares of common stock that
may be deemed to be beneficially owned by GS Capital Partners V
Fund, L.P. and its general partner, GSCP V Advisors, L.L.C.,
(2) 8,466,218 shares of common stock that may be
deemed to be beneficially owned by GS Capital Partners V
Offshore Fund, L.P. and its general partner, GSCP V Offshore
Advisors, L.L.C., (3) 5,620,242 shares of common stock
that may be deemed to be beneficially owned by GS Capital
Partners V Institutional, L.P. and its general partner, GSCP V
Advisors, L.L.C., and (4) 649,793 shares of common
stock that may be deemed to be beneficially owned by GS Capital
Partners V GmbH & Co. KG and its general partner,
Goldman, Sachs Management GP GmbH. Kenneth A. Pontarelli is a
partner managing director of Goldman, Sachs & Co. and
Scott L. Lebovitz is a managing director of Goldman,
Sachs & Co. Mr. Pontarelli, Mr. Lebovitz,
The Goldman Sachs Group, Inc. and Goldman, Sachs & Co.
each disclaims beneficial ownership of the shares of common
stock owned directly or indirectly by the Goldman Sachs Funds,
except to the extent of their pecuniary interest therein, if any.
|
|
(3)
|
|
Mr. Lipinski owns 247,471 shares of common stock
directly. In addition, Mr. Lipinski owns
158,285 shares indirectly through his ownership of common
units in Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC. Mr. Lipinski does not have the
power to vote or dispose of shares that correspond to his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and thus does not have
beneficial ownership of such shares. Mr. Lipinski also owns
(i) profits interests in each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, (ii) phantom
points under each of the Phantom Unit Plans and
(iii) common units and override units in Coffeyville
Acquisition III LLC. See Compensation Discussion and
Analysis Outstanding Equity Awards at 2007 Fiscal
Year-End and Compensation Discussion and
Analysis Equity Awards at 2007 Fiscal Year-End That
Have Vested. Such interests do not give Mr. Lipinski
beneficial ownership of any
|
210
|
|
|
|
|
shares of our common stock because they do not give
Mr. Lipinski the power to vote or dispose of any such
shares.
|
|
(4)
|
|
Mr. Riemann owns no shares of common stock directly.
Mr. Riemann owns 97,408 shares indirectly through his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC. Mr. Riemann does not
have the power to vote or dispose of shares that correspond to
his ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and thus does not have
beneficial ownership of such shares. Mr. Riemann also owns
(i) profits interests in each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, (ii) phantom
points under each of the Phantom Unit Plans and
(iii) common units and override units in Coffeyville
Acquisition III LLC. See Compensation Discussion and
Analysis Outstanding Equity Awards at 2007 Fiscal
Year- End and Compensation Discussion and
Analysis Equity Awards at 2007 Fiscal Year-End That
Have Vested. Such interests do not give Mr. Riemann
beneficial ownership of any shares of our common stock because
they do not give Mr. Riemann the power to vote or dispose
of any such shares.
|
|
(5)
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Mr. Rens owns no shares of common stock directly.
Mr. Rens owns 60,879 shares indirectly through his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC. Mr. Rens does not have
the power to vote or dispose of shares that correspond to his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and thus does not have
beneficial ownership of such shares. Mr. Rens also owns
(i) profits interests in each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, (ii) phantom
points under each of the Phantom Unit Plans and
(iii) common units and override units in Coffeyville
Acquisition III LLC. See Compensation Discussion and
Analysis Outstanding Equity Awards at 2007 Fiscal
Year-End and Compensation Discussion and
Analysis Equity Awards at 2007 Fiscal Year-End That
Have Vested. Such interests do not give Mr. Rens
beneficial ownership of any shares of our common stock because
they do not give Mr. Rens the power to vote or dispose of
any such shares.
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(6)
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Mr. Haugen owns 5,000 shares of common stock directly.
Mr. Haugen owns 24,352 shares indirectly through his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC. Mr. Haugen does not
have the power to vote or dispose of shares that correspond to
his ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and thus does not have
beneficial ownership of such shares. Mr. Haugen also owns
(i) profits interests in each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, (ii) phantom
points under each of the Phantom Unit Plans and
(iii) common units and override units in Coffeyville
Acquisition III LLC. See Compensation Discussion and
Analysis Outstanding Equity Awards at 2007 Fiscal
Year-End and Compensation Discussion and
Analysis Equity Awards at 2007 Fiscal Year-End That
Have Vested. Such interests do not give Mr. Haugen
beneficial ownership of any shares of our common stock because
they do not give Mr. Haugen the power to vote or dispose of
any such shares.
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(7)
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Mr. Daly owns no shares of common stock directly.
Mr. Daly owns 12,176 shares indirectly through his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC. Mr. Daly does not have
the power to vote or dispose of shares that correspond to his
ownership of common units in Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC and thus does not have
beneficial ownership of such shares. Mr. Daly also owns
(i) profits interests in each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, (ii) phantom
points under each of the Phantom Unit Plans and
(iii) common units and override units in Coffeyville
Acquisition III LLC. See Compensation Discussion and
Analysis Outstanding Equity Awards at 2007 Fiscal
Year-End and Compensation Discussion and
Analysis Equity Awards at 2007 Fiscal Year-End That
Have Vested. Such interests do not give Mr. Daly
beneficial ownership of any shares of our common stock because
they do not give Mr. Daly the power to vote or dispose of
any such shares.
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(8)
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In connection with our initial public offering, our board
awarded 5,000 shares of non-vested restricted stock to
Mr. Lippert. The date of grant for these shares of
restricted stock was October 24, 2007. Under the terms of
the restricted stock agreement, Mr. Lippert has the right
to vote his shares of restricted stock after the date of grant.
However, the transfer restrictions on these shares will
generally lapse in one-third annual increments beginning on the
first anniversary of the date of grant. Because Mr. Lippert
has the right to vote his non-vested shares of restricted stock,
he is deemed to have beneficial ownership of such shares. In
addition, our board awarded Mr. Lippert options to purchase
5,150 shares of common stock with an exercise price equal
to the initial public offering price of our
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211
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common stock, which was $19.00 per share. The date of grant for
these options was October 22, 2007. These options will
generally vest in one-third annual increments beginning on the
first anniversary of the date of grant. Additionally, our board
awarded Mr. Lippert options to purchase 4,300 shares
of common stock with an exercise price equal to the closing
price of our common stock on the date of grant, which was
$24.73. The date of grant for these options was
December 21, 2007. These options will generally vest in
one-third annual increments beginning on the first anniversary
of the date of grant. Additionally, members of
Mr. Lipperts immediate family own 2,500 shares
of our common stock directly. Mr. Lippert disclaims
beneficial ownership of shares of our common stock owned by
members of his immediate family.
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(9)
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In connection with joining our board in June 2008, our board
awarded Mr. Nordaker options to purchase 4,350 shares
of common stock with an exercise price equal to the closing
price of our common stock on the date of grant, which was
$24.96. The date of grant for these options was June 10,
2008. These options will generally vest in one-third annual
increments beginning on the first anniversary of the date of
grant.
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(10)
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In connection with our initial public offering, our board
awarded 12,500 shares of non-vested restricted stock to
Mark Tomkins. The date of grant for these shares of restricted
stock was October 24, 2007. Under the terms of the
restricted stock agreement, Mr. Tomkins has the right to
vote his shares of restricted stock after the date of grant.
However, the transfer restrictions on these shares will
generally lapse in one-third annual increments beginning on the
first anniversary of the date of grant. Because Mr. Tomkins
has the right to vote his non-vested shares of restricted stock,
he is deemed to have beneficial ownership of such shares. In
addition, our board awarded Mr. Tomkins options to purchase
5,150 shares of common stock with an exercise price equal
to the initial public offering price of our common stock, which
was $19.00 per share. The date of grant for these options was
October 22, 2007. These options will generally vest in
one-third annual increments beginning on the first anniversary
of the date of grant. Additionally, our board awarded
Mr. Tomkins options to purchase 4,300 shares of common
stock with an exercise price equal to the closing price of our
common stock on the date of grant, which was $24.73. The date of
grant for these options was December 21, 2007. These
options will generally vest in one-third annual increments
beginning on the first anniversary of the date of grant.
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(11)
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The number of shares of common stock owned by all directors and
executive officers, as a group, reflects the sum of (1) all
shares of common stock directly owned by Coffeyville Acquisition
LLC, with respect to which Messrs. George Matelich and
Stanley de J. Osborne may be deemed to share beneficial
ownership, (2) all shares of common stock directly owned by
Coffeyville Acquisition II LLC, with respect to which
Messrs. Kenneth A. Pontarelli and Scott L. Lebovitz may be
deemed to share beneficial ownership, (3) the
247,471 shares of common stock owned directly by
Mr. John J. Lipinski, the 1,000 shares of common stock
owned directly by Mr. Gross, the 5,000 shares of
common stock owned directly by Mr. Haugen, the
3,500 shares of common stock owned directly by
Mr. Jernigan, the 1,000 shares of common stock owned
directly by Mr. Vick and the 1,000 shares of common
stock owned directly by Mr. Swanberg, (4) the
12,500 shares owned by Mr. Tomkins and (5) the
5,000 shares owned by Mr. Lippert and the
2,500 shares owned by members of Mr. Lipperts
family.
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212
Distributions of
the Proceeds of this Offering by Coffeyville Acquisition and
Coffeyville Acquisition II
Coffeyville Acquisition and Coffeyville Acquisition II
expect to distribute the proceeds of their sale of common stock
in this offering to their members pursuant to their respective
limited liability company agreements. If all of the shares of
common stock of our Company to be sold in this offering by
Coffeyville Acquisition and Coffeyville Acquisition II were
sold at $24.92 per share, which was the price of our common
stock on June 16, 2008, after giving effect to the
underwriting discount, each of the entities and individuals
named below would receive the following approximate amounts:
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Distribution if
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Distribution if
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Underwriters Option
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Underwriters Option
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Entity / Individual
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is not Exercised
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is Exercised in Full
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The Goldman Sachs Funds
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$
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113,675,494
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|
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$
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130,345,080
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The Kelso Funds
|
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111,896,782
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|
|
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128,305,534
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John J. Lipinski
|
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3,488,826
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|
|
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4,270,538
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Stanley A. Riemann
|
|
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1,613,338
|
|
|
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1,974,864
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James T. Rens
|
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871,197
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|
|
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1,062,613
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Robert W. Haugen
|
|
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749,569
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|
|
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921,423
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Daniel J. Daly, Jr.
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519,703
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|
|
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640,758
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All executive officers, as a group
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8,912,303
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10,328,499
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All management members, as a group
|
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10,412,670
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|
|
|
12,738,798
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All other members, as a group
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|
2,001,050
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|
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2,294,488
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Payment to be
made by the Company in respect of Phantom Points held by Our
Named Executive Officers as a result of this Offering by
Coffeyville
Acquisition and Coffeyville Acquisition II
If all of the shares of common stock of our Company to be sold
in this offering by Coffeyville Acquisition and Coffeyville
Acquisition II were sold at $24.92 per share, which was the
price of our common stock on June 16, 2008, after giving
effect to the underwriting discount, each of the individuals
named below would receive the following approximate amounts from
the Company pursuant to the Phantom Unit Plans:
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Distribution if
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Distribution if
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|
Underwriters Option
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|
Underwriters Option
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|
Individual
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|
is not Exercised
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is Exercised in Full
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John J. Lipinski
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$
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485,111
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|
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$
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590,816
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Stanley A. Riemann
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211,312
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|
|
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257,356
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James T. Rens
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|
|
175,541
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|
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213,792
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Robert W. Haugen
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|
|
175,541
|
|
|
|
213,792
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Daniel J. Daly, Jr.
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|
|
195,796
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|
|
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238,461
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All executive officers, as a group
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|
|
2,181,226
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|
|
|
2,656,515
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All management members, as a group
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3,488,382
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|
|
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4,248,501
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All other members, as a group
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56,228
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|
|
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68,480
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213
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
This section describes related party transactions between CVR
Energy (and its predecessors) and its directors, executive
officers and 5% stockholders. For a description of transactions
between CVR Energy and the Partnership, whose managing general
partner is owned by our controlling stockholders and senior
management, see The Nitrogen Fertilizer Limited
Partnership.
Transactions with
the Goldman Sachs Funds and the Kelso Funds
Investments in
Coffeyville Acquisition LLC
Prior to our initial public offering in October 2007, GS Capital
Partners V Fund, L.P. and related entities, or the Goldman Sachs
Funds, and Kelso Investment Associates VII, L.P. and related
entity, or the Kelso Funds, were the majority owners of
Coffeyville Acquisition LLC. Other members of Coffeyville
Acquisition LLC were John J. Lipinski, Stanley A. Riemann, James
T. Rens, Edmund Gross, Robert W. Haugen, Wyatt E. Jernigan,
Kevan A. Vick, Christopher Swanberg, Wesley Clark, Magnetite
Asset Investors III L.L.C. and other members of our
management team.
On June 24, 2005, pursuant to a stock purchase agreement
dated May 15, 2005, between Coffeyville Group Holdings, LLC
and Coffeyville Acquisition LLC, Coffeyville Acquisition LLC
acquired all of the subsidiaries of Coffeyville Group Holdings,
LLC. The Goldman Sachs Funds made capital contributions of
$112,817,500 to Coffeyville Acquisition LLC and the Kelso Funds
made capital contributions of $110,817,500 to Coffeyville
Acquisition LLC in connection with the acquisition. The total
proceeds received by Pegasus Partners II, L.P. and the other
unit holders of Coffeyville Group Holdings, LLC, including then
current management, in connection with the Subsequent
Acquisition was $526,185,017, after repayment of Immediate
Predecessors credit facility.
Coffeyville Acquisition LLC paid companies related to the
Goldman Sachs Funds and the Kelso Funds each equal amounts
totaling $6.0 million for the transaction fees related to
the Subsequent Acquisition, as well as an additional
$0.7 million paid to the Goldman Sachs Funds for reimbursed
expenses related to the Subsequent Acquisition.
On July 25, 2005, the following executive officers and
directors made the following capital contributions to
Coffeyville Acquisition LLC: John J. Lipinski, $650,000; Stanley
A. Riemann, $400,000; James T. Rens, $250,000; Kevan A. Vick,
$250,000; Robert W. Haugen, $100,000; Wyatt E. Jernigan,
$100,000; Chris Swanberg, $25,000. On September 12, 2005,
Edmund Gross made a $30,000 capital contribution to Coffeyville
Acquisition LLC. On September 20, 2005, Wesley Clark made a
$250,000 capital contribution to Coffeyville Acquisition LLC.
All but two of the executive officers received common units,
operating units and value units of Coffeyville Acquisition LLC
and the director received common units of Coffeyville
Acquisition LLC.
On September 14, 2005, the Goldman Sachs Funds and the
Kelso Funds each invested an additional $5.0 million in
Coffeyville Acquisition LLC. On May 23, 2006, the Goldman
Sachs Funds and the Kelso Funds each invested an additional
$10.0 million in Coffeyville Acquisition LLC. In each case
they received additional common units of Coffeyville Acquisition
LLC.
On December 28, 2006, the directors of Coffeyville
Acquisition LLC approved a cash dividend of $244,710,000 to
companies related to the Goldman Sachs Funds and the Kelso Funds
and $3,360,393 to certain members of our management team,
including John J. Lipinski ($914,844), Stanley A. Riemann
($548,070), James T. Rens ($321,180), Kevan A. Vick ($321,180),
Robert W. Haugen ($164,680) and Wyatt E. Jernigan ($164,680), as
well as Wesley Clark ($241,205).
Split of
Coffeyville Acquisition LLC
As part of the restructuring transactions that occurred
immediately prior to our initial public offering, Coffeyville
Acquisition LLC redeemed all of its outstanding common units
held by the Goldman Sachs Funds in exchange for the same number
of common units in Coffeyville Acquisition II LLC, a newly
formed limited liability company to which Coffeyville
Acquisition LLC transferred half of its interests in each of
Coffeyville Refining & Marketing Holdings, Inc.,
Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy. In
addition, half of the common units and override units in
Coffeyville Acquisition
214
LLC held by each executive officer and Wesley Clark were
redeemed in exchange for an equal number of common units and
override units in Coffeyville Acquisition II LLC. As a
result of these restructuring transactions, the Kelso Funds
became the majority owner of Coffeyville Acquisition LLC and the
Goldman Sachs Funds became the majority owner of Coffeyville
Acquisition II LLC, and management and Wesley Clark
retained an equivalent interest in each of Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC.
Stockholders
Agreement
In October 2007, we entered into a stockholders agreement with
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC. Pursuant to the agreement, for so long as Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC
collectively beneficially own in the aggregate an amount of our
common stock that represents at least 40% of our outstanding
common stock, Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC each have the right to designate two
directors to our board of directors so long as that party holds
an amount of our common stock that represents 20% or more of our
outstanding common stock and one director to our board of
directors so long as that party holds an amount of our common
stock that represents less than 20% but more than 5% of our
outstanding common stock. If Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC cease to collectively
beneficially own in the aggregate an amount of our common stock
that represents at least 40% of our outstanding common stock,
the foregoing rights become a nomination right and the parties
to the stockholders agreement are not obligated to vote for each
others nominee. In addition, the stockholders agreement
contains certain tag-along rights with respect to certain
transfers (other than underwritten offerings to the public) of
shares of common stock by the parties to the stockholders
agreement. For so long as Coffeyville Acquisition LLC and
Coffeyville Acquisition II LLC beneficially own in the
aggregate at least 40% of our common stock, (i) each such
stockholder that has the right to designate at least two
directors will have the right to have at least one of its
designated directors on any committee (other than the audit
committee and conflicts committee), to the extent permitted by
SEC or NYSE rules, (ii) directors designated by the
stockholders will be a majority of each such committee (at least
50% in the case of the compensation committee and the nominating
committee), and (iii) the chairman of each such committee
will be a director designated by such stockholder.
Registration
Rights Agreements
In October 2007 we entered into a registration rights agreement
with Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC pursuant to which we may be required to
register the sale of our shares held by Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC and permitted
transferees. Under the registration rights agreement, the
Goldman Sachs Funds and the Kelso Funds each have the right to
request that we register the sale of shares held by Coffeyville
Acquisition LLC or Coffeyville Acquisition II LLC, as
applicable, on their behalf on three occasions including
requiring us to make available shelf registration statements
permitting sales of shares into the market from time to time
over an extended period. In addition, the Goldman Sachs Funds
and the Kelso Funds have the ability to exercise certain
piggyback registration rights with respect to their own
securities if we elect to register any of our equity securities.
The registration rights agreement also includes provisions
dealing with holdback agreements, indemnification and
contribution, and allocation of expenses. All of our shares held
by Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC are entitled to these registration
rights.
Dividend
In connection with our initial public offering in October 2007,
the directors of Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, respectively, approved a special
dividend of approximately $10.6 million to their members,
including $5,227,584 to the Goldman Sachs Funds, $5,145,787 to
the Kelso Funds, $81,798 to Magnetite Asset Investors III
L.L.C. and $103,269 to certain members of our senior management
team and Wesley K. Clark. The common unitholders receiving this
special dividend then contributed approximately
$10.6 million collectively to Coffeyville
215
Acquisition III LLC, which used such amounts to acquire CVR
GP, LLC, the managing general partner of the Partnership, from
us.
J.
Aron & Company
In June 2005 Coffeyville Acquisition LLC entered into commodity
derivative contracts in the form of three swap agreements for
the period from July 1, 2005 through June 30, 2010
with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. (the
Cash Flow Swap). These agreements were assigned to
Coffeyville Resources, LLC, a subsidiary of the Company, on
June 24, 2005. Based on crude oil capacity of
115,000 bpd, the Cash Flow Swap represents approximately
58% and 14% of crude oil capacity for the periods July 1,
2008 through June 30, 2009 and July 1, 2009 through
June 30, 2010, respectively. Under the terms of our credit
facility (the Credit Facility), upon meeting
specific requirements related to our leverage ratio and our
credit ratings, we are permitted to reduce the Cash Flow Swap to
35,000 bpd, or approximately 30% of expected crude oil
capacity, for the period from April 1, 2008 through
December 31, 2008 and terminate the Cash Flow Swap in 2009
and 2010, so long as at the time of reduction or termination, we
pay the amount of unrealized losses associated with the amount
reduced or terminated. The Cash Flow Swap has resulted in
unrealized gains (losses) of approximately
$(235.9) million, $126.8 million and
$(103.2) million for the years ended December 31,
2005, 2006 and 2007, respectively. See Managements
Discussion and Analysis of Financial Condition and Results of
Operations Critical Accounting Policies
Derivative Instruments and Fair Value of Financial
Instruments and Description of Our Indebtedness and
the Cash Flow Swap Cash Flow Swap.
As a result of the flood and the temporary cessation of our
Companys operations on June 30, 2007, Coffeyville
Resources, LLC was required to enter into several deferral
agreements with J. Aron with respect to the Cash Flow Swap.
These deferral agreements deferred to August 31, 2008 the
payment of approximately $123.7 million (plus accrued
interest) which we owed to J. Aron. We are required to use 37.5%
of our consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferred amounts.
During 2007 we were party to a crude oil supply agreement with
J. Aron. On December 31, 2007, we entered into an amended
and restated crude oil supply agreement with J. Aron. The terms
of the agreement provide that we will obtain all of the crude
oil for our refinery through J. Aron, other than crude oil that
we acquire in Kansas, Missouri, Oklahoma, Wyoming and all states
adjacent thereto. Pursuant to the agreement, we identify crude
oil and pricing terms that meet our requirements and from time
to time notify J. Aron of sourcing opportunities that we deem
acceptable. We
and/or
J.
Aron negotiate the cost of each barrel of crude oil that is
purchased from third party crude oil suppliers. J. Aron executes
all third party sourcing transactions and provides
transportation and other logistical services for the crude oil
it delivers to us. We generally pay J. Aron a fixed supply
service fee per barrel over the negotiated cost of each barrel
of crude oil purchased. In some cases, J. Aron will sell crude
oil directly to us without having executed a specific third
party sourcing transaction.
Coffeyville Acquisition LLC also entered into certain crude oil,
heating oil and gasoline option agreements with J. Aron as of
May 16, 2005. These agreements expired unexercised on
June 16, 2005 and resulted in an expense of $25,000,000
reported in the accompanying consolidated statements of
operations as a gain (loss) on derivatives for the 233 days
ended December 31, 2005.
As a result of the refinery turnaround in early 2007, we needed
to delay the processing of quantities of crude oil that we
purchased from various small independent producers. In order to
facilitate this anticipated delay, we entered into a purchase,
storage and sale agreement for gathered crude oil, dated
March 20, 2007, with J. Aron. Pursuant to the terms of the
agreement, J. Aron agreed to purchase gathered crude oil from
us, store the gathered crude oil and sell us the gathered crude
oil on a forward basis. This agreement is no longer in effect.
Consulting and
Advisory Agreements
Under the terms of separate consulting and advisory agreements,
dated June 24, 2005, between Coffeyville Acquisition LLC
and each of Goldman, Sachs & Co. and Kelso &
Company, L.P., Coffeyville
216
Acquisition LLC was required to pay an advisory fee of
$1,000,000 per year, payable quarterly in advance, to each of
Goldman Sachs and Kelso for consulting and advisory services
provided by Goldman Sachs and Kelso. Payments relating to the
consulting and advisory agreements include $1,310,416,
$2,315,937 and $1,703,990 which was expensed in selling,
general, and administrative expenses for the 233 days ended
December 31, 2005, the year ended December 31, 2006
and the year ended December 31, 2007, respectively. These
agreements were terminated in connection with our initial public
offering in October 2007 and each of Goldman, Sachs &
Co. and Kelso & Company, L.P. received a one-time fee
of $5 million by reason of such termination in conjunction
with the offering.
Credit
Facilities
Goldman Sachs Credit Partners L.P., an affiliate of Goldman,
Sachs & Co., or Goldman Sachs, is one of the lenders
under the Credit Facility. Goldman Sachs Credit Partners is also
a joint lead arranger and bookrunner under the Credit Facility.
In addition, Goldman Sachs Credit Partners L.P. was the sole
arranger and sole bookrunner of the $25.0 million secured
facility, the $25.0 million unsecured facility, and the
$75.0 million unsecured facility, each of which was
terminated in connection with the consummation of our initial
public offering in October 2007. Goldman Sachs Credit Partners
was also a lender, sole lead arranger, sole bookrunner and
syndication agent under our first lien credit agreement and a
lender and joint lead arranger, joint bookrunner and syndication
agent under our second lien credit agreement. The first lien
credit agreement and second lien credit agreement were entered
into in connection with the acquisition of Coffeyville Group
Holdings, LLC and its subsidiaries by Coffeyville Acquisition
LLC in June 2005. At that time, we paid this Goldman Sachs
affiliate a $22.1 million fee included in deferred
financing costs. In conjunction with the financing that occurred
on December 28, 2006, we paid approximately
$8.1 million to a Goldman Sachs affiliate. Additionally, in
conjunction with entering into the $25.0 million secured
facility, the $25.0 million unsecured facility, and the
$75.0 million unsecured facility on August 23, 2007,
we paid approximately $1.3 million in fees and associated
expense reimbursement to a Goldman Sachs affiliate. For the
233 days ended December 31, 2005, Successor made
interest payments to this Goldman Sachs affiliate of
$1.8 million recorded in interest expense and paid letter
of credit fees of approximately $155,000 which were recorded in
selling, general, and administrative expenses. See
Description of Our Indebtedness and the Cash Flow
Swap.
Guarantees
During 2007 one of the Goldman Sachs Funds and one of the Kelso
Funds each guaranteed 50% of our payment obligations under the
Cash Flow Swap in the amount of $123.7 million, plus
accrued interest. These guarantees remain in effect as of the
date of this prospectus.
In addition, in August 2007 these funds also guaranteed our
obligations under the $25.0 million secured facility, the
$25.0 million unsecured facility and the $75.0 million
unsecured facility. These guarantees were terminated when the
credit facilities were repaid and terminated in connection with
the consummation of our initial public offering in October 2007.
Initial Public
Offering and Convertible Senior Notes Offering
Goldman, Sachs & Co. was the lead underwriter of our
initial public offering in October 2007. Goldman,
Sachs & Co. was paid a customary underwriting discount
for serving as underwriter. Goldman, Sachs & Co. is
also the lead underwriter for our concurrent offering of
$125 million aggregate principal amount of Convertible
Senior Notes due 2013.
Secondary
Offering
Coffeyville Acquisition and Coffeyville Acquisition II
expect to distribute the proceeds of their sale of common stock
in this offering to their members pursuant to their respective
limited liability company agreements. The Kelso Funds are the
principal owners of Coffeyville Acquisition, and the Goldman
Sachs Funds are the principal owners of Coffeyville Acquisition
II. Members of our senior management team own interests in both
Coffeyville Acquisition and Coffeyville Acquisition II and
will receive
217
proceeds from the sale of shares of our common stock by
Coffeyville Acquisition and Coffeyville Acquisition II. See
Principal and Selling Stockholders.
Transactions with
Directors and Senior Management
On June 30, 2005, Coffeyville Acquisition LLC loaned
$500,000 to John J. Lipinski, CEO of Successor. This loan
accrued interest at the rate of 7% per year. The loan was made
in conjunction with Mr. Lipinskis purchase of 50,000
common units of Coffeyville Acquisition LLC. Mr. Lipinski
repaid $150,000 of principal and paid $17,643.84 in interest on
January 13, 2006. The unpaid loan balance of $350,000,
together with accrued and unpaid interest of $17,989, was
forgiven in full in September 2006.
On December 28, 2006, the directors of Coffeyville Nitrogen
Fertilizers, Inc. approved the issuance of shares of common
stock of Coffeyville Nitrogen Fertilizers, Inc., par value $0.01
per share, to John J. Lipinski in exchange for $10.00 pursuant
to a Subscription Agreement. Mr. Lipinski also entered into
a Stockholders Agreement with Coffeyville Nitrogen Fertilizers,
Inc. and Coffeyville Acquisition LLC at the same time he entered
into the Subscription Agreement. Pursuant to the Stockholders
Agreement, among other things, Coffeyville Acquisition LLC had
the right to exchange all shares of common stock in Coffeyville
Nitrogen Fertilizers, Inc. held by Mr. Lipinski for such
number of common units of Coffeyville Acquisition LLC or equity
interests of a wholly-owned subsidiary of Coffeyville
Acquisition LLC, in each case having a fair market value equal
to the fair market value of the common stock in Coffeyville
Nitrogen Fertilizers, Inc. held by Mr. Lipinski.
On December 28, 2006, the directors of Coffeyville
Refining & Marketing, Inc. approved the issuance of
shares of common stock of Coffeyville Refining &
Marketing, Inc., par value $0.01 per share, to John J. Lipinski
in exchange for $10.00 pursuant to a Subscription Agreement.
Mr. Lipinski entered into a stockholders agreement with
Coffeyville Refining & Marketing, Inc. similar to the
agreement he entered into with Coffeyville Nitrogen Fertilizers,
Inc.
In August 2007, Mr. Lipinskis shares of common stock
in Coffeyville Refining & Marketing, Inc. were
exchanged for an equivalent number of shares of common stock in
Coffeyville Refining & Marketing Holdings, Inc.
Mr. Lipinski also entered into a Stockholders Agreement
with Coffeyville Refining & Marketing Holdings, Inc.
and Coffeyville Acquisition LLC at the time of the exchange.
Pursuant to the Stockholders Agreement, among other things,
Coffeyville Acquisition LLC had the right to exchange all shares
of common stock in Coffeyville Refining & Marketing
Holdings, Inc. held by Mr. Lipinski for such number of
common units of Coffeyville Acquisition LLC or equity interests
of a wholly-owned subsidiary of Coffeyville Acquisition LLC, in
each case having a fair market value equal to the fair market
value of the common stock in Coffeyville Refining &
Marketing Holdings, Inc. held by Mr. Lipinski.
In October 2007, prior to our initial public offering, we
entered into a subscription agreement with Mr. Lipinski
pursuant to which Mr. Lipinski agreed to exchange his
shares of common stock of Coffeyville Nitrogen Fertilizers, Inc.
and Coffeyville Refining & Marketing Holdings, Inc.
for shares of our common stock. In accordance with this
agreement, we issued 247,471 shares of common stock to
Mr. Lipinski. Prior to that stock issuance,
Mr. Lipinski owned approximately 0.3128% of Coffeyville
Refining and Marketing Holdings, Inc. and approximately 0.6401%
of Coffeyville Nitrogen Fertilizer, Inc. These two companies
owned all of the interests which became owned by CVR Energy upon
the completion of its initial public offering. The allocation of
value as of September 30, 2007 between Coffeyville Refining
and Marketing Holdings, Inc. and Coffeyville Nitrogen
Fertilizer, Inc. was 75.7717% and 24.2283%, respectively. The
allocation of value was based on the two entities respective
ownership interest in their subsidiaries taking into effect
liabilities and receivables existing between the two companies.
The number of shares issued to Mr. Lipinski was determined
by grossing up the shares after our stock split by the weighted
average percentage ownership of Mr. Lipinski in
218
the two entities and multiplying the result by
Mr. Lipinskis weighted average percentage ownership.
The table below illustrates the calculations of the shares
issued to Mr. Lipinski.
|
|
|
|
|
|
|
|
|
Relative ownership in all interests contributed to CVR
Energy
|
|
|
|
|
A
|
|
Coffeyville Refining and Marketing Holdings, Inc.
|
|
|
75.7717
|
%
|
B
|
|
Coffeyville Nitrogen Fertilizer, Inc.
|
|
|
24.2283
|
%
|
|
|
Mr. Lipinskis Interests in the subsidiaries
|
|
|
|
|
D
|
|
Coffeyville Refining and Marketing Holdings, Inc.
|
|
|
0.3128
|
%
|
E
|
|
Coffeyville Nitrogen Fertilizer, Inc.
|
|
|
0.6401
|
%
|
|
|
Weighted average ownership in all assets
|
|
|
|
|
F: = A x D
|
|
Coffeyville Refining and Marketing Holdings, Inc.
|
|
|
0.23701
|
%
|
G: = B x E
|
|
Coffeyville Nitrogen Fertilizer, Inc.
|
|
|
0.15509
|
%
|
H: = F + G
|
|
Mr. Lipinskis weighted average ownership interest
|
|
|
0.3921
|
%
|
I
|
|
Original shares
|
|
|
100.00
|
|
J
|
|
Stock split
|
|
|
628,667.20
|
|
K: = I x J
|
|
Shares to members of Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC
|
|
|
62,866,720.00
|
|
L: = H x ( K/(1-H))
|
|
Mr. Lipinskis shares
|
|
|
247,471.00
|
|
M: = K + L
|
|
Total shares before director shares, our initial public offering
and employee shares
|
|
|
63,114,191
|
|
N: = L/M
|
|
Mr. Lipinskis percentage of pre-offering shares
|
|
|
0.3921
|
%
|
As a record holder of CVR Energy common stock on
October 16, 2007, Mr. Lipinski received a dividend of
$41,562 as part of a $10.6 million dividend approved by CVR
Energys board of directors in October 2007.
All decisions concerning Mr. Lipinskis compensation
were approved by the compensation committee of Coffeyville
Acquisition LLC without Mr. Lipinskis participation.
Registration
Rights Agreement
In October 2007, we entered into a registration rights agreement
with John J. Lipinski. Under the registration rights agreement,
Mr. Lipinski will have the ability to exercise certain
piggyback registration rights with respect to his own securities
if any of our equity securities are offered to the public
pursuant to a registration statement. The registration rights
agreement also includes provisions dealing with holdback
agreements, indemnification and contribution, and allocation of
expenses. All of the shares in our company held directly by John
J. Lipinski are entitled to these registration rights.
Wesley Clark
Consulting Agreement
In connection with his retirement from our board of directors,
we entered into a consulting agreement with General Wesley Clark
whereby Mr. Clark will provide consulting and advisory services
to us for a two year period in exchange for a monthly retainer
of $2,000. As a member of the board of directors, Mr. Clark
had been granted 244,038 Phantom Performance Points and 244,038
Phantom Services Points (together, the Points) under
the Coffeyville Resources, LLC Phantom Unit Plan. Upon his
leaving the board, Mr. Clark forfeited these Points. As
additional compensation for his services as a consultant,
Mr. Clark will receive a payment equal to the amounts that
would have been distributed to Mr. Clark in respect of 65%
of his Points had he continued to hold them during the period
beginning on the annual meeting date and ending on the earlier
of (i) December 1, 2010 or (ii) the date of the
consummation of an Exit Event (as defined in the Coffeyville
Acquisition LLC Limited Liability Company Agreement) (but no
earlier than January 15, 2009) (the Payment
Date). In addition, Mr. Clark will receive the amount
that would have been distributed in respect of 65% of his Points
on the Payment Date assuming that (i) Mr. Clark
remained on the board, (ii) all of the common stock of the
Company then held by Coffeyville Acquisition LLC and Coffeyville
Acquisition LLC II was sold at the closing price of common stock
on the New York Stock Exchange on such Payment Date and
(iii) the proceeds were distributed to the members of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC on such Payment Date pursuant to the LLC Agreements of each
of Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC.
219
Transactions with
Pegasus Partners II, L.P.
Pegasus Partners II, L.P., or Pegasus, was a majority owner of
Coffeyville Group Holdings, LLC (Immediate Predecessor) during
the period March 3, 2004 through June 24, 2005. On
March 3, 2004, Coffeyville Group Holdings, LLC, through its
wholly owned subsidiary, Coffeyville Resources, LLC, acquired
the assets of the former Farmland petroleum division and one
facility within Farmlands nitrogen fertilizer
manufacturing and marketing division through a bankruptcy court
auction process for approximately $107 million and the
assumption of approximately $23 million of liabilities.
On March 3, 2004, Coffeyville Group Holdings, LLC entered
into a management services agreement with Pegasus Capital
Advisors, L.P., pursuant to which Pegasus Capital Advisors, L.P.
provided Coffeyville Group Holdings, LLC with managerial and
advisory services. In consideration for these services,
Coffeyville Group Holdings, LLC agreed to pay Pegasus Capital
Advisors, L.P. an annual fee of up to $1.0 million plus
reimbursement for any out-of-pocket expenses. During the year
ended December 31, 2004, Immediate Predecessor paid an
aggregate of approximately $545,000 to Pegasus Capital Advisors,
L.P. in fees under this agreement. $1,000,000 was expensed to
selling, general, and administrative expenses for the
174 days ended June 23, 2005. In addition, Immediate
Predecessor paid approximately $455,000 in legal fees on behalf
of Pegasus Capital Advisors, L.P. in lieu of the remaining
amount owed under the management fee. This management services
agreement terminated at the time of the Subsequent Acquisition
in June 2005.
Coffeyville Group Holdings, LLC paid Pegasus Capital Advisors,
L.P. a $4.0 million transaction fee upon closing of the
acquisition on March 3, 2004. The transaction fee related
to a $2.5 million merger and acquisition fee and
$1.5 million in deferred financing costs. In addition, in
conjunction with the refinancing of our senior secured credit
facility on May 10, 2004, Coffeyville Group Holdings, LLC
paid an additional $1.25 million fee to Pegasus Capital
Advisors, L.P. as a deferred financing cost.
On March 3, 2004, Coffeyville Group Holdings, LLC entered
into Executive Purchase and Vesting Agreements with the then
executive officers listed below providing for the sale by
Immediate Predecessor to them of the number of our common units
to the right of each executive officers name at a purchase
price of approximately $0.0056 per unit. Pursuant to the terms
of these agreements, as amended, each executive officers
common units were to vest at a rate of 16.66% every six months
with the first 16.66% vesting on November 10, 2004. In
connection with their purchase of the common units pursuant to
the Executive Purchase and Vesting Agreements, each of the
executive officers at that time issued promissory notes in the
amounts indicated below. These notes were paid in full on
May 10, 2004.
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Amount of
|
|
|
|
Common
|
|
|
Promissory
|
|
Executive Officer
|
|
Units
|
|
|
Note
|
|
|
Philip L. Rinaldi
|
|
|
3,717,647
|
|
|
$
|
21,000
|
|
Abraham H. Kaplan
|
|
|
2,230,589
|
|
|
$
|
12,600
|
|
George W. Dorsey
|
|
|
2,230,589
|
|
|
$
|
12,600
|
|
Stanley A. Riemann
|
|
|
1,301,176
|
|
|
$
|
7,350
|
|
James T. Rens
|
|
|
371,764
|
|
|
$
|
2,100
|
|
Keith D. Osborn
|
|
|
650,588
|
|
|
$
|
3,675
|
|
Kevan A. Vick
|
|
|
650,588
|
|
|
$
|
3,675
|
|
On May 10, 2004, Mr. Rinaldi entered into another
Executive Purchase and Vesting Agreement under the same terms as
described above providing for the purchase of an additional
500,000 common units of Coffeyville Group Holdings, LLC for an
aggregate purchase price of $2,850.
On May 10, 2004, Coffeyville Group Holdings, LLC refinanced
its existing long-term debt with a $150 million term loan
and used the proceeds of the borrowings to repay the outstanding
borrowings under Coffeyville Group Holdings, LLCs previous
credit facility. The borrowings were also used to distribute a
$99,987,509 dividend, which included a preference payment of
$63,200,000 plus a yield of $1,802,956 to the preferred unit
holders and a $63,000 payment to the common unit holders for
220
undistributed capital per the LLC agreement. The remaining
$34,921,553 was distributed to the preferred and common unit
holders pro rata according to their ownership percentages, as
determined by the aggregate of the common and preferred units.
On October 8, 2004, Coffeyville Group Holdings, LLC entered
into a joint venture with The Leiber Group, Inc., a company
whose majority stockholder was Pegasus Partners II, L.P., the
principal stockholder of Immediate Predecessor. In connection
with the joint venture, Coffeyville Group Holdings, LLC
contributed approximately 68.7% of its membership interests in
Coffeyville Resources, LLC to CL JV Holdings, LLC, a Delaware
limited liability company, or CL JV Holdings, and The Leiber
Group, Inc. contributed the Judith Leiber business to CL JV
Holdings. At the time of the Subsequent Acquisition, in June
2005, the joint venture was effectively terminated.
On January 13, 2005, Immediate Predecessors board of
directors authorized the following bonus payments to the
following then executive officers, at that time, in recognition
of the importance of retaining their services:
|
|
|
|
|
Executive Officer
|
|
Bonus Amount
|
|
|
Philip L. Rinaldi
|
|
$
|
1,000,000
|
|
Abraham H. Kaplan
|
|
$
|
600,000
|
|
George W. Dorsey
|
|
$
|
300,000
|
|
Stanley A. Riemann
|
|
$
|
700,000
|
|
James T. Rens
|
|
$
|
150,000
|
|
Keith D. Osborn
|
|
$
|
150,000
|
|
Kevan A. Vick
|
|
$
|
150,000
|
|
Edmund S. Gross
|
|
$
|
200,000
|
|
During 2004 and 2005, Immediate Predecessor shared office space
with Pegasus in New York, New York for which we paid Pegasus
$10,000 per month.
On June 23, 2005, immediately prior to the Subsequent
Acquisition, Coffeyville Group Holdings, LLC used available cash
balances to distribute a $52,211,493 dividend to its preferred
and common unit holders pro rata according to their ownership
percentages, as determined by the aggregate of the common and
preferred units.
Other
Transactions
We paid INTERCAT, Inc. $525,507 during 2006 for chemical
additives. Mr. Regis B. Lippert, a director of our company,
is the principal shareholder and chief executive officer of
INTERCAT, Inc. Mr. John J. Lipinski, the chief executive
officer and president of our company and a member of our board
of directors, is a director and member of the compensation
committee of INTERCAT, Inc.
Related Party
Transaction Policy
Our board of directors has adopted a Related Party Transaction
Policy, which is designed to monitor and ensure the proper
review, approval, ratification and disclosure of related party
transactions involving us. This policy applies to any
transaction, arrangement or relationship (or any series of
similar transactions, arrangements or relationships) in which we
were, are or will be a participant and the amount involved
exceeds $100,000, and in which any related party had, has or
will have a direct or indirect material interest. The audit
committee of our board of directors must review, approve and
ratify a related party transaction if such transaction is
consistent with the Related Party Transaction Policy and is on
terms, taken as a whole, which the audit committee believes are
no less favorable to us than could be obtained in an arms-length
transaction with an unrelated third party, unless the audit
committee otherwise determines that the transaction is not in
our best interests. Any related party transaction or
modification of such transaction which our board of directors
has approved or ratified by the affirmative vote of a majority
of directors, who do not have a direct or indirect material
interest in such transaction, does not need to be approved or
ratified by our audit committee. In addition, related party
transactions involving compensation will be approved by our
compensation committee in lieu of our audit committee.
221
Conflicts of
Interests Policy for Transactions between the Partnership and
Us
Our board of directors has also adopted a Conflicts of Interests
Policy, which is designed to monitor and ensure the proper
review, approval, ratification and disclosure of transactions
between the Partnership and us. The policy applies to any
transaction, arrangement or relationship (or any series of
similar transactions, arrangements or relationships) between us
or any of our subsidiaries, on the one hand, and the
Partnership, its managing general partner and any subsidiary of
the Partnership, on the other hand. According to the policy, all
such transactions must be fair and reasonable to us. If such
transaction is expected to involve a value, over the life of
such transaction, of less than $1 million, no special
procedures will be required. If such transaction is expected to
involve a value of more than $1 million but less than
$5 million, it is deemed to be fair and reasonable to us if
(i) such transaction is approved by the conflicts committee
of our board of directors, (ii) the terms of such
transaction are no less favorable to us than those generally
being provided to or available from unrelated third parties or
(iii) such transaction, taking into account the totality of
any other such transaction being entered into at that time
between the parties involved (including other transaction that
may be particularly favorable or advantageous to us), is
equitable to CVR Energy. If such transaction is expected to
involve a value, over the life of such transaction, of
$5 million or more, it is deemed to be fair and reasonable
to us if it has been approved by the conflicts committee of our
board of directors.
222
THE NITROGEN
FERTILIZER LIMITED PARTNERSHIP
Background
In June 2007, we created a new limited partnership, CVR
Partners, LP, or the Partnership. In October 2007, prior to our
initial public offering, we transferred our nitrogen fertilizer
business to this Partnership. The Partnership initially had
three partners: a managing general partner, CVR GP, LLC, which
we owned; a special general partner, CVR Special GP, LLC, which
we owned; and a limited partner, Coffeyville Resources, LLC. We
sold the managing general partner for $10.6 million to
Coffeyville Acquisition III LLC, a newly created entity
owned by the Goldman Sachs Funds, the Kelso Funds, our executive
officers, Mr. Wesley Clark, Magnetite Asset
Investors III L.L.C. and other members of our senior
management team.
In connection with the creation of the Partnership, CVR GP, LLC,
as the managing general partner, Coffeyville Resources, LLC, as
the limited partner, and CVR Special GP, LLC, as a general
partner, entered into a limited partnership agreement which set
forth the various rights and responsibilities of the partners in
the Partnership. In addition, we entered into a number of
intercompany agreements with the Partnership and the managing
general partner which regulate certain business relations among
us, the Partnership and the managing general partner.
Contribution,
Conveyance and Assumption Agreement
In October 2007, the Partnership entered into a contribution,
conveyance and assumption agreement, or the contribution
agreement, with the Partnerships managing general partner,
CVR Special GP, LLC (our subsidiary that holds a general partner
interest in the Partnership), and Coffeyville Resources, LLC
(our subsidiary that holds a limited partner interest in the
Partnership). Pursuant to the contribution agreement,
Coffeyville Resources, LLC transferred our subsidiary that owns
the nitrogen fertilizer business to the Partnership in exchange
for (1) the issuance to CVR Special GP, LLC of 30,303,000
special GP units, representing a 99.9% general partner interest
in the Partnership, (2) the issuance to Coffeyville
Resources, LLC of 30,333 special LP units, representing a 0.1%
limited partner interest in the Partnership, (3) the
issuance to the managing general partner of the managing general
partner interest in the Partnership and (4) the agreement
by the Partnership, contingent upon the Partnership consummating
an initial public or private offering, to reimburse us for
capital expenditures we incurred during the two year period
prior to the sale of the managing general partner to Coffeyville
Acquisition III LLC, in connection with the operations of
the fertilizer plant (currently estimated to be
$18.4 million). The Partnership assumed all liabilities
arising out of or related to the ownership of the nitrogen
fertilizer business to the extent arising or accruing on and
after the date of transfer.
Sale of Managing
General Partner to Coffeyville Acquisition III
LLC
Following formation of the Partnership pursuant to the
contribution agreement in October 2007, the following entities
and individuals contributed the following amounts in cash to
Coffeyville Acquisition III LLC, a newly formed entity
owned by our controlling stockholders and executive officers.
223
Coffeyville Acquisition III LLC used these contributions to
purchase the managing general partner of the Partnership from us:
|
|
|
|
|
Contributing Parties
|
|
Amount Contributed
|
|
The Goldman Sachs Funds
|
|
$
|
5,227,584
|
|
The Kelso Funds
|
|
|
5,145,787
|
|
John J. Lipinski
|
|
|
68,146
|
|
Stanley A. Riemann
|
|
|
16,359
|
|
James T. Rens
|
|
|
10,225
|
|
Edmund S. Gross
|
|
|
1,227
|
|
Robert W. Haugen
|
|
|
4,090
|
|
Wyatt E. Jernigan
|
|
|
4,090
|
|
Kevan A. Vick
|
|
|
10,225
|
|
Christopher G. Swanberg
|
|
|
1,022
|
|
Daniel J. Daly, Jr.
|
|
|
2,045
|
|
Wesley Clark
|
|
|
10,225
|
|
Others
|
|
|
98,975
|
|
Total Contribution
|
|
$
|
10,600,000
|
|
Coffeyville Acquisition III purchased the managing general
partner from us for $10.6 million, which our board of
directors determined, after consultation with management,
represented the fair market value of the managing general
partner of the Partnership at that time. The valuation of the
managing general partner interest was based on a discounted cash
flow analysis, using a discount rate commensurate with the risk
profile of the managing general partner interest. The key
assumptions underlying the analysis were commodity price
projections, which were used to estimate the Partnerships
raw material costs and output revenues. Other business expenses
of the Partnership were estimated based on managements
projections. The Partnerships cash distributions were
assumed to be flat at expected forward fertilizer prices, with
cash reserves developed in periods of high prices and cash
reserves reduced in periods of lower prices. The
Partnerships projected cash distributions to the managing
general partner under the terms of the Partnerships
partnership agreement used for the valuation were modeled based
on the structure of the Partnership, the managing general
partners incentive distribution rights (IDRs)
and managements expectations of the Partnerships
operations, including production volumes and operating costs,
which were developed by management based on historical
experience. As commodity price curve projections were key
assumptions in the discounted cash flow analysis, alternative
price curve projections were considered in order to test the
reasonableness of these assumptions, which gave management an
added level of assurance as to such reasonableness. Price
projections were based on information received from Blue Johnson
and Associates, a fertilizer industry consultant in the United
States which we routinely use for fertilizer market analysis.
There can be no assurance that the value of the managing general
partner will not differ in the future from the amount initially
paid for it.
February 2008
Filing of
Form S-1
by CVR Partners, LP
On February 28, 2008, the Partnership filed a
Form S-1
registration statement (the Partnership
S-1)
with the SEC for an initial public offering (the
Partnership Offering) of common units representing
limited partner interests in the Partnership. On June 13,
2008, the Company announced that the managing general partner of
the Partnership had decided that it would postpone indefinitely
the Partnerships initial public offering. The Partnership
may elect to move forward with a public or private offering in
the future.
Description of
Partnership Interests Initially Following Formation
The partnership agreement provides that initially the
Partnership has three types of partnership interests:
(1) special GP units, representing special general partner
interests, which are owned by the special general partner,
(2) special LP units, representing a limited partner
interest, which are owned
224
by Coffeyville Resources, LLC, and (3) a managing general
partner interest which has associated IDRs which are held by the
managing general partner.
Special Units.
The special units
include special GP units and special LP units. We indirectly own
all 30,303,000 special GP units and all 30,333 special LP units.
The special GP units are special general partner interests
giving the holder thereof specified joint management rights
(which we refer to as special GP rights), including rights with
respect to the appointment, termination and compensation of the
chief executive officer and the chief financial officer of the
managing general partner, and entitling the holder to
participate in Partnership distributions and allocations of
income and loss. Special LP units have identical voting and
distribution rights as the special GP units, but represent
limited partner interests in the Partnership and do not give the
holder thereof the special GP rights.
In accordance with the partnership agreement, the special units
are entitled to payment of a set target distribution of $0.4313
per unit ($13.1 million in the aggregate for all our
special units each quarter), or $1.7252 per unit on an
annualized basis ($52.3 million in the aggregate for all
our special units annually), prior to the payment of any
quarterly distribution in respect of the IDRs. For more
information on cash distributions to the special units and the
IDRs please see Cash Distributions by the
Partnership. We are permitted to sell the special units at
any time without the consent of the managing general partner,
subject to compliance with applicable securities laws, but upon
any sale of special GP units to an unrelated third party the
special GP rights will no longer apply to such units.
Managing General Partner Interest.
The
managing general partner interest, which is held solely by the
managing general partner, entitles the holder to manage (subject
to our special GP rights) the business and operations of the
Partnership, but does not entitle the holder to participate in
Partnership distributions or allocations except in respect of
associated IDRs. IDRs represent the right to receive an
increasing percentage of quarterly distributions of available
cash from operating surplus after the target distribution
($0.4313 per unit per quarter) has been paid and following
distribution of the aggregate adjusted operating surplus
generated by the Partnership during the period from
October 24, 2007 through December 31, 2009 to the
special units
and/or
the
common and subordinated units (if issued). In addition, there
can be no distributions paid on the managing general
partners IDRs for so long as the Partnership or its
subsidiaries are guarantors under our Credit Facility. The IDRs
are not transferable apart from the general partner interest.
The managing general partner can be sold without the consent of
other partners in the Partnership.
Provisions
Regarding an Initial Offering by the Partnership
Under the partnership agreement, the managing general partner
has the sole discretion to cause the Partnership to undertake an
initial private or public offering, subject to our joint
management rights (as holder of the special GP rights, described
below) if the offering involves the issuance of more than
$200 million of the Partnerships interests (exclusive
of the underwriters option, if any). There is no assurance
that the Partnership will undertake or consummate a public or
private offering.
Under the contribution agreement, if Fertilizer GP elects to
cause the Partnership to undertake an initial private or public
offering (in either case, the Partnerships initial
offering), Fertilizer GP must give prompt notice to us of
such election and the proposed terms of the offering. We have
agreed to use our commercially reasonable efforts to take such
actions as Fertilizer GP reasonably requests in order to
effectuate and permit the consummation of the offering. We have
agreed that Fertilizer GP may structure the initial offering to
include (1) a secondary offering of interests by us or
(2) a primary offering of interests by the Partnership,
possibly together with an incurrence of indebtedness by the
Partnership, where a use of proceeds is to redeem units from us
(with a
per-unit
redemption price equal to the price at which each unit is
purchased from the Partnership, net of sales commissions or
underwriting discounts) (a special GP offering),
provided that in either case the number of units associated with
the special GP offering is reasonably expected by Fertilizer GP
to generate no more than $100 million in net proceeds to us
(exclusive of the underwriters option, if any). The
special GP offering may not be consummated without our consent
if the net proceeds to us are less than $10 per unit. If the
initial public offering includes a special GP offering, unless
we otherwise agree with the
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Partnership, the special GP offering will be increased to cover
our pro rata portion of any exercise of the underwriters
option, if any.
Under the contribution agreement, if Fertilizer GP reasonably
determines that, in order to consummate the initial offering, it
is necessary or appropriate for the Partnership and its
subsidiaries to be released from their obligations under our
Credit Facility and our swap arrangements with J. Aron, then
Fertilizer GP must give prompt written notice to us describing
the requested amendments. The notice must be given 90 days
prior to the anticipated closing date of the initial offering.
We will be required to use our commercially reasonable efforts
to effect the releases or amendments. We will not be considered
to have made commercially reasonable efforts if we
do not effect such requested modifications due to
(i) payment of fees to the lenders or the swap
counterparty, (ii) the costs of this type of amendment,
(iii) an increase in applicable margins or spreads or
(iv) changes to the terms required by the lenders including
covenants, events of default and repayment and prepayment
provisions; provided that (i), (ii), (iii) and (iv) in
the aggregate are not likely to have a material adverse effect
on us. In order to effect the requested modifications, we may
require that (1) the initial offering include a special GP
offering generating at least $140 million in net proceeds
to us and (2) the Partnership raise an amount of cash (from
the issuance of equity or incurrence of indebtedness) equal to
$75.0 million minus the amount of capital expenditures for
which it will reimburse us from the proceeds of its initial
public or private offering and distribute that cash to us prior
to, or concurrently with, the closing of its initial public or
private offering.
If the Partnership consummates an initial public or private
offering and we sell units, or our units are redeemed, in a
special GP offering, or the Partnership makes a distribution to
us of proceeds of the offering or debt financing, such sale,
redemption or distribution would likely result in taxable gain
to us and such taxable gain could be significant. If the
Partnership consummates an initial public or private offering,
regardless of whether we sell units, the distributions that we
receive from the Partnership could decrease because the
Partnerships distributions will be shared with the new
limited partners. Additionally, when the Partnership issues
units or engages in certain other transactions, the Partnership
will determine the fair market value of its assets and allocate
any unrealized gain or loss attributable to those assets to the
capital accounts of the existing partners. As a result of this
revaluation and the Partnerships adoption of the remedial
allocation method under Section 704(c) of the Internal
Revenue Code (i) new unitholders will be allocated
deductions as if the tax basis of the Partnerships
property were equal to the fair market value thereof at the time
of the offering, and (ii) we will be allocated
reverse Section 704(c) allocations of income or
loss over time consistent with our allocation of unrealized gain
or loss.
If the Partnership consummates an initial offering as either a
primary or secondary offering, our special units, other than
those sold or redeemed in a special GP offering, if any, will be
converted into a combination of (1) common units and
(2) subordinated units. The special units will be converted
into common units and subordinated units, on a one-for-one
basis, such that the lesser of (1) 40% of all outstanding
units after the initial offering (prior to the exercise of the
underwriters option, if any) and (2) all of the units
owned by us, will be subordinated. For a description of the
common units and subordinated units please see
Description of Partnership Interests Following
Initial Offering. The special GP units will convert into
common GP units or subordinated GP units and the special LP
units will convert into common LP units or subordinated LP units.
The following table sets forth the number of special GP units
and special LP units that are currently outstanding and
illustrates the number of common GP units, subordinated GP
units, common LP units and subordinated LP units we will own, as
well as the number of common LP units that public unitholders
will own, assuming the Partnerships initial offering
involves a total of 10 million common LP units,
7 million of which are our special units (converted into
common LP units immediately prior to sale directly in the
initial offering, or redeemed using the proceeds from the
issuance of common LP units by the Partnership) and
3 million of which are new common LP units. The following
table assumes that the 7 million of our special units sold
or redeemed reduce our special LP units and special GP units pro
rata (i.e., 99.9% from our special GP units and 0.1% from our
special LP units).
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This information is presented for illustrative purposes only.
There can be no assurance the Partnership will undertake an
initial offering consistent with these assumptions or at all.
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Initial
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Following Partnership Initial Offering
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Special Units
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Common Units
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Subordinated Units
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Owned by us
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30,303,000
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9,990,000
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13,320,000
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special GP
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common GP
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subordinated GP
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units
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units
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units
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30,333
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10,000
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13,333
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special LP
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common LP
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subordinated LP
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units
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units
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units
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Owned by public
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10,000,000
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common LP
units
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The partnership agreement prohibits Fertilizer GP from causing
the Partnership to undertake or consummate an initial offering
unless the board of directors of Fertilizer GP determines, after
consultation with us, that the Partnership will likely be able
to earn and pay the minimum quarterly distribution (which is
currently set at $0.375 per unit) on all units for each of the
two consecutive, nonoverlapping four-quarter periods following
the initial offering. As an illustration, the Partnership would
need to earn and pay $50 million during each of the two
consecutive, nonoverlapping four-quarter periods based upon the
number of units (i.e., 33,333,333 total units) in the
hypothetical illustrated in the table above. If Fertilizer GP
determines that the Partnership is not likely to be able to earn
and pay the minimum quarterly distribution for such periods,
Fertilizer GP may, in its sole discretion and effective upon
closing of the initial offering, reduce the minimum quarterly
distribution to an amount it determines to be appropriate and
likely to be earned and paid during such periods.
The contribution agreement also provides that if the initial
offering is not consummated by October 24, 2009, Fertilizer
GP can require us to purchase the managing general partner
interest. This put right expires on the earlier of
(1) October 24, 2012 and (2) the closing of the
Partnerships initial offering. If the Partnerships
initial offering is not consummated by October 24, 2012, we
have the right to require Fertilizer GP to sell the managing
general partner interest to us. This call right expires on the
closing of the Partnerships initial offering. In the event
of an exercise of a put right or a call right, the purchase
price will be the fair market value of the managing general
partner interest at the time of purchase. The fair market value
will be determined by an independent investment banking firm
selected by us and Fertilizer GP. The independent investment
banking firm may consider the value of the Partnerships
assets, the rights and obligations of Fertilizer GP and other
factors it may deem relevant but the fair market value shall not
include any control premium. See Risk Factors
Risks Related to the Limited Partnership Structure Through Which
We Hold Our Interest in the Nitrogen Fertilizer
Business If the Partnership does not consummate an
initial offering by October 24, 2009, Fertilizer GP can
require us to purchase its managing general partner interest in
the Partnership. We may not have requisite funds to do so.
Description of
Partnership Interests Following Initial Offering
Common Units.
The common units, if
issued, will be comprised of common GP units and common LP
units. The common GP units will be special general partner
interests giving the holder special GP rights (described above),
including rights with respect to the appointment, termination
and compensation of the chief executive officer and the chief
financial officer of the managing general partner, and entitling
the holder to participate in Partnership distributions and
allocations on a pro rata basis with common LP units. Common LP
units will have identical voting and distribution rights as the
common GP units, but will represent limited partner interests in
the Partnership and will not give the holder thereof special GP
rights. The common units will be entitled to payment of the
minimum quarterly distribution prior to the payment of any
quarterly distribution on the subordinated units or the IDRs.
For more information of the rights and preferences of holders of
the common units,
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subordinated units and IDRs in the Partnerships
distributions, please see Cash Distributions
by the Partnership.
We will be permitted to sell the common units we own at any time
without the consent of the managing general partner, subject to
compliance with applicable securities laws. The common GP units
will automatically convert to common LP units immediately prior
to sale thereof to an unrelated third party. The common GP units
will automatically convert into common LP units (with no special
GP rights) immediately if the holder of the common GP units,
together with all of its affiliates, ceases to own 15% or more
of all units of the Partnership (not including the managing
general partner interest).
Subordinated Units.
The subordinated
units, if issued, will be comprised of subordinated GP units and
subordinated LP units. The subordinated GP units will be special
general partner interests giving the holder special GP rights.
Subordinated LP units will have identical voting and
distribution rights as the subordinated GP units, but will
represent limited partner interests in the Partnership and will
not give the holder thereof special GP rights. The subordinated
units will entitle the holder to participate in Partnership
distributions and allocations on a subordinated basis to the
common units (as described in Cash
Distributions by the Partnership). During the
subordination period, the subordinated units will not be
entitled to receive any distributions until the common units
have received the set minimum quarterly distribution plus any
arrearages from prior quarters. Furthermore, no arrearages will
be paid on the subordinated units. As a result, if the
Partnership consummates an initial offering, the portion of our
special units that are converted into subordinated units will be
subordinated to the common units and may not receive
distributions unless and until the common units have received
the minimum quarterly distribution, plus any accrued and unpaid
arrearages in the minimum quarterly distribution from prior
quarters. See Risk Factors Risks Related to
the Limited Partnership Structure Through Which We Hold Our
Interest In the Nitrogen Fertilizer Business Our
rights to receive distributions from the Partnership may be
limited over time and Risk Factors Risks
Related to the Limited Partnership Structure Through Which We
Hold Our Interest In the Nitrogen Fertilizer
Business If the Partnership completes a public
offering or private placement of limited partner interests, our
voting power in the Partnership would be reduced and our rights
to distributions from the Partnership could be materially
adversely affected.
We will be permitted to sell the subordinated units we own at
any time without the consent of the managing general partner,
subject to compliance with applicable securities laws. The
subordinated units will automatically convert into common units
on the second day after the distribution of cash in respect of
the last quarter in the subordination period (which will end no
earlier than five years after the initial offering), although up
to 50% may convert earlier. The subordinated GP units will
automatically convert to subordinated LP units immediately prior
to sale thereof to an unrelated third party. The subordinated GP
units will automatically convert into subordinated LP units
immediately if the holder of the subordinated GP units, together
with all of its affiliates, ceases to own 15% or more of all
units of the Partnership.
Managing General Partner Interest.
The
managing general partner interest will continue to be
outstanding following the initial offering.
Management of the
Partnership
The managing general partner manages the Partnerships
operations and activities, subject to our joint management
rights, as specified in the partnership agreement. Among other
things, the managing general partner has sole authority to
effect an initial public or private offering of the Partnership,
including the right to determine the timing, size (subject to
our consent rights for any initial offering in excess of
$200 million, exclusive of the underwriters option,
if any) and underwriters or initial purchasers, if any, for any
initial offering. The Partnerships managing general
partner is wholly-owned by an entity controlled by the Goldman
Sachs Funds, the Kelso Funds and certain members of our senior
management team. The operations of the managing general partner,
in its capacity as the managing general partner of the
Partnership, are managed by its board of directors. As of the
date of this prospectus, the board of directors of the managing
general partner consisted of Donna R. Ecton, John J. Lipinski,
Scott L. Lebovitz, George E. Matelich, Frank M.
Muller, Jr., Stanley
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de J. Osborne and Kenneth A. Pontarelli. Actions by the managing
general partner that are made in its individual capacity will be
made by the sole member of the managing general partner and not
by its board of directors. The managing general partner is not
elected by the unitholders or us and is not subject to
re-election on a regular basis in the future. The officers of
the managing general partner manage the day-to-day affairs of
the Partnerships business.
The special general partner, which we own, has special
management rights. The special management rights will terminate
if we cease to own 15% of more of all units of the Partnership.
Our management rights include:
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appointment rights and consent rights for the termination of
employment and compensation of the chief executive officer and
chief financial officer of the managing general partner, not to
be exercised unreasonably (our approval for appointment of an
officer is deemed given if the officer is an executive officer
of CVR Energy);
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the right to appoint two directors to the board of directors of
the managing general partner and one such director to any
committee thereof (subject to certain exceptions);
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consent rights over any merger by the Partnership into another
entity where:
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for so long as we own 50% or more of all units of the
Partnership immediately prior to the merger, less than 60% of
the equity interests of the resulting entity are owned by the
pre-merger unitholders of the Partnership;
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for so long as we own 25% or more of all units of the
Partnership immediately prior to the merger, less than 50% of
the equity interests of the resulting entity are owned by the
pre-merger unitholders of the Partnership; and
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for so long as we own more than 15% of all of the units of the
Partnership immediately prior to the merger, less than 40% of
the equity interests of the resulting entity are owned by the
pre-merger unitholders of the Partnership;
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consent rights over any purchase or sale, exchange or other
transfer of assets or entities with a purchase/sale price equal
to 50% or more of the Partnerships asset value; and
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consent rights over any incurrence of indebtedness or issuance
of Partnership interests with rights to distribution or in
liquidation ranking prior or senior to the common units, in
either case in excess of $125 million ($200 million in
the case of the Partnerships initial public or private
offering, exclusive of the underwriters option, if any),
increased by 80% of the purchase price for assets or entities
whose purchase was approved by us as described in the
immediately preceding bullet point.
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As of the date of this prospectus, the board of directors of the
managing general partner consists of seven directors, including
two representatives of the Goldman Sachs Funds, two
representatives of the Kelso Funds, Donna R. Ecton and Frank M.
Muller, Jr., who are independent directors and John J.
Lipinksi, chief executive officer and president of the managing
general partner and CVR Energy. If the Partnership effects an
initial public offering in the future, the board of directors of
the managing general partner will be required, subject to
phase-in requirements of any national securities exchange upon
which the Partnerships common units are listed for
trading, to have at least three members who are not officers or
employees, and are otherwise independent, of the entity which
owns the managing general partner, and its affiliates, including
CVR Energy and the Partnerships general partners. In
addition, if an initial public offering of the Partnership
occurs, the board of directors of the managing general partner
will be required to maintain an audit committee comprised of at
least three independent directors.
The partnership agreement permits the board of directors of the
managing general partner to establish a conflicts committee,
comprised of at least one independent director, that may
determine if the resolution of a conflict of interest with the
Partnerships general partners or their affiliates is fair
and reasonable to the Partnership. Any matters approved by the
conflicts committee will be conclusively deemed to be fair and
reasonable to the Partnership, approved by all of the
Partnerships
229
partners and not a breach by the general partners of any duties
they may owe the Partnership or the unitholders of the
Partnership.
Cash
Distributions by the Partnership
Available Cash.
The partnership
agreement requires the Partnership to make quarterly
distributions of 100% of its available cash.
Available cash generally means, for each fiscal quarter, all
cash on hand at the end of the quarter
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less the amount of cash reserves established by the managing
general partner to:
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provide for the proper conduct of the Partnerships
business (including the satisfaction of obligations in respect
of pre-paid fertilizer contracts, future capital expenditures,
anticipated future credit needs and the payment of expenses and
fees, including payments to the managing general partner);
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comply with applicable law or any loan agreement, security
agreement, mortgage, debt instrument or other agreement or
obligation to which the Partnership or any of its subsidiaries
is a party or by which the Partnership is bound or its assets
are subject; and
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provide funds for distributions in respect of any one or more of
the next eight quarters, provided, however, that following an
initial public offering of the Partnership, the managing general
partner may not establish cash reserves pursuant to this clause
if the effect of such reserves would be that the Partnership
would be unable to distribute the minimum quarterly distribution
on all common units and any cumulative common unit arrearages
thereon with respect to any such quarter;
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plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter. Working capital borrowings
are generally borrowings that are used solely for working
capital purposes or to make distributions to partners.
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Cash distributions will be made within 45 days after the
end of each quarter. The amount of distributions paid by the
Partnership and the decision to make any distribution will be
determined by the managing general partner, taking into
consideration the terms of the partnership agreement.
Prior to the earlier to occur of (i) such time as the
limitations described below in Non-IDR surplus
amount no longer apply, after which time available cash
from operating surplus could be distributed in respect of the
IDRs, assuming each unit has received at least the first target
distribution, as described below, and (ii) an initial
offering by the Partnership, after which there will be limited
partners to whom available cash could be distributed, all
available cash is distributed to us, as holder of the special
units. Because all available cash is currently distributed to
us, the board of directors of Fertilizer GP has not adopted a
formal distribution policy.
Operating Surplus and Capital
Surplus.
All cash distributed by the
Partnership will be characterized either as operating surplus or
capital surplus. The Partnership will distribute available cash
from operating surplus differently than available cash from
capital surplus.
Definition of Operating Surplus.
Operating
surplus for any period generally consists of:
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$60 million (as described below); plus
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all of the Partnerships cash receipts after formation
(reset to the date of the Partnerships initial offering if
an initial offering occurs), excluding cash from interim
capital transactions (as described below); plus
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working capital borrowings made after the end of a quarter but
before the date of determination of operating surplus for the
quarter; plus
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cash distributions paid on equity interests issued by the
Partnership to finance all or any portion of the construction,
expansion or improvement of the Partnerships facilities
during the period from such financing until the earlier to occur
of the date the capital asset is put into service or the date it
is abandoned or disposed of; plus
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cash distributions paid on equity interests issued by the
Partnership to pay the construction period interest on debt
incurred, or to pay construction period distributions on equity
issued, to finance the construction, expansion and improvement
projects referred to above; less
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all of the Partnerships operating expenditures
(as defined below) after formation (reset to the date of closing
of the Partnerships initial offering if an initial
offering occurs); less
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the amount of cash reserves established by the managing general
partner to provide funds for future operating expenditures
(which does not include expansion capital expenditures).
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If a working capital borrowing, which increases operating
surplus, is not repaid during the twelve-month period following
the borrowing, it will be deemed repaid at the end of such
period, thus decreasing operating surplus at such time. When
such working capital borrowing is in fact repaid, it will not be
treated as a reduction in operating surplus because operating
surplus will have been previously reduced by the deemed
repayment.
As described above, operating surplus does not reflect actual
cash on hand that is available for distribution to unitholders.
For example, it includes a provision that will enable the
Partnership, if it chooses, to distribute as operating surplus
up to $60 million of cash from non-operating sources such
as asset sales, issuances of securities and long-term borrowings
that would otherwise be distributed as capital surplus. In
addition, the effect of including, as described above, certain
cash distributions on equity interests in operating surplus
would be to increase operating surplus by the amount of any such
cash distributions.
Operating expenditures generally means all of the
Partnerships expenditures, including its expenses, taxes,
reimbursements or payments of expenses to its managing general
partner, repayment of working capital borrowings, debt service
payments and capital expenditures, provided that operating
expenditures will not include:
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repayments of working capital borrowings, if such working
capital borrowings were outstanding for twelve months, not
repaid, but deemed repaid, thus decreasing operating surplus at
such time;
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payments (including prepayments) of principal of and premium on
indebtedness, other than working capital borrowings;
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expansion capital expenditures;
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investment capital expenditures;
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payment of transaction expenses relating to interim
capital transactions; or
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distributions to partners.
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Where capital expenditures are made in part for expansion and in
part for other purposes, the managing general partner shall
determine the allocation between the amounts paid for each.
Interim capital transactions means the following
transactions if they occur prior to liquidation of the
Partnership: (a) borrowings, refinancings or refundings of
indebtedness (other than working capital borrowings and other
than for items purchased on open account or for a deferred
purchase price in the ordinary course of business);
(b) sales of equity interests and debt securities; and
(c) sales or other voluntary or involuntary dispositions of
any assets other than (i) sales or other dispositions of
inventory, accounts receivable and other assets in the ordinary
course of business, and (ii) sales or other dispositions of
assets as part of normal retirements or replacements of assets.
Maintenance capital expenditures reduce operating surplus, but
expansion capital expenditures and investment capital
expenditures do not. Maintenance capital expenditures represent
capital expenditures to replace partially or fully depreciated
assets to maintain the Partnerships operating capacity (or
productivity) or capital base. Maintenance capital expenditures
include expenditures required to maintain equipment reliability,
plant integrity and safety and to address environmental laws and
regulations. Maintenance capital expenditures also include
interest (and related fees) on debt incurred and distributions
on equity issued to finance all or any portion of the
construction,
231
improvement or development of a replacement asset that is paid
during the period that begins when the Partnership enters into a
binding commitment or commences constructing or developing a
replacement asset and ending on the earlier to occur of the date
any such replacement asset commences commercial service or the
date it is abandoned or disposed of.
Expansion capital expenditures include expenditures to acquire
or construct assets to grow the Partnerships business and
to expand fertilizer production capacity. Expansion capital
expenditures also include interest (and related fees) on debt
incurred and distributions on equity issued to finance all or
any portion of the construction of such a capital improvement
during the period that commences when the Partnership enters
into a binding obligation to commence construction of a capital
improvement and ending on the date such capital improvement
commences commercial service or the date that it is abandoned or
disposed of.
Investment capital expenditures are those capital expenditures
that are neither maintenance capital expenditures nor expansion
capital expenditures. Investment capital expenditures largely
consist of capital expenditures made for investment purposes.
Examples of investment capital expenditures include traditional
capital expenditures for investment purposes, such as purchases
of securities, as well as other capital expenditures that might
be made in lieu of such traditional investment capital
expenditures, such as the acquisition of a capital asset for
investment purposes or development of facilities that are in
excess of the maintenance of the Partnerships existing
operating capacity or productivity, but which are not expected
to expand for the long-term the Partnerships operating
capacity or asset base.
As described above, none of the Partnerships investment
capital expenditures or expansion capital expenditures are
subtracted from operating surplus. Because investment capital
expenditures and expansion capital expenditures include interest
payments (and related fees) on debt incurred and distributions
on equity issued to finance all of the portion of the
construction, replacement or improvement of a capital asset
during the period that begins when the Partnership enters into a
binding obligation to commence construction of a capital
improvement and ending on the earlier to occur of the date any
such capital asset commences commercial service or the date that
it is abandoned or disposed of, such interest payments and
equity distributions are also not subtracted from operating
surplus.
The officers and directors of the managing general partner
determine how to allocate a capital expenditure for the
acquisition or expansion of the Partnerships assets
between maintenance capital expenditures and expansion capital
expenditures.
Definition of Capital Surplus.
Capital
surplus is generally generated only by:
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borrowings other than working capital borrowings;
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sales of debt securities and equity interests; and
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sales or other dispositions of assets for cash, other than
inventory, accounts receivable and other current assets sold in
the ordinary course of business or as part of the normal
retirement or replacement of assets.
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Distributions
from Operating Surplus.
The Partnerships distribution structure with respect to
operating surplus will change based upon the occurrence of three
events: (1) distribution by the Partnership of the non-IDR
surplus amount (as defined below), together with a release of
the guarantees by the Partnership and its subsidiaries of our
Credit Facility, (2) occurrence of an initial offering by
the Partnership (following which all or a portion of our
interest will be converted into subordinated units and the
minimum quarterly distribution could be reduced) and
(3) expiration (or early termination) of the subordination
period.
Minimum Quarterly Distributions.
The
minimum quarterly distribution, or MQD, represents the set
quarterly distribution amount that the common units, if issued,
will be entitled to prior to the payment of any quarterly
distribution on the subordinated units. The amount of the MQD is
set in Partnerships partnership agreement at $0.375 per
unit, or $1.50 per unit on an annualized basis. The
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partnership agreement prohibits the managing general partner
from causing the Partnership to undertake or consummate an
initial offering unless the board of directors of the managing
general partner, after consultation with us, concludes that the
Partnership will be likely to be able to earn and pay the MQD on
all units for each of the two consecutive, nonoverlapping
four-quarter periods following the initial offering. If the
managing general partner determines that the Partnership is not
likely to be able to earn and pay the MQD for such periods, the
managing general partner may, in its sole discretion and
effective upon closing of the initial offering, reduce the MQD
to an amount it determines to be appropriate and likely to be
earned and paid during such periods. If the Partnership were to
distribute $0.375 per unit on the number of units we own, we
would receive a quarterly distribution of $11.4 million in
the aggregate. The MQD for any period of less than a full
calendar quarter (e.g., the periods before and after the closing
of an initial offering by the Partnership) will be adjusted
based on the actual length of the periods. To the extent we
receive such amounts from the Partnership in the form of
quarterly distributions, we will generally not be able to
distribute such amounts to our stockholders due to restrictions
contained in our Credit Facility. See Dividend
Policy.
Target Distributions.
The
Partnerships partnership agreement provides for
target distribution levels. After the limitations
described below in Non-IDR surplus
amount no longer apply, the managing general
partners IDRs will entitle it to receive increasing
percentages of any incremental quarterly cash distributed by the
Partnership as the target distribution levels for each quarter
are exceeded. There are three target distribution levels set in
the partnership agreement: $0.4313, $0.4688 and $0.5625,
representing 115%, 125% and 150%, respectively, of the initial
MQD amount. The target distribution levels for any period of
less than a full calendar quarter (e.g., the periods before and
after the closing of an initial offering by the Partnership)
will be adjusted based on the actual length of the periods. The
target distribution levels will not be adjusted in connection
with any reduction of the MQD in connection with the
Partnerships initial offering unless we otherwise agree
with the managing general partner.
The following table illustrates the percentage allocations of
available cash from operating surplus between the unitholders
and the Partnerships managing general partner up to and
above the various target distribution levels. The amounts set
forth under marginal percentage interest in
distributions are the percentage interests of the
Partnerships managing general partner and the unitholders
in any available cash from operating surplus the Partnership
distributes up to and including the corresponding amount in the
column Total Quarterly Distribution Target
Amount, until the available cash from operating surplus
the Partnership distributes reaches the next target distribution
level, if any. The percentage interests shown for the
unitholders and managing general partner for the minimum
quarterly distribution are also applicable to quarterly
distribution amounts that are less than the minimum quarterly
distribution. The percentage interests set forth below for the
managing general partner represent distributions in respect of
the IDRs.
Marginal
Percentage Interest in Distributions
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Total Quarterly
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Distribution Target
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Managing General
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Amount
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Special Units
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Partner
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Minimum Quarterly Distribution
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$0.375
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100
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%
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0
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%
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First Target Distribution
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Up to $0.4313
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100
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%
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0
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%
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Second Target Distribution
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Above $0.4313
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87
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%
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13
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%
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and up to $0.4688
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Third Target Distribution
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Above $0.4688
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77
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%
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23
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%
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and up to $0.5625
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Thereafter
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Above $0.5625
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52
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%
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48
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%
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If legislation is enacted or if existing law is modified or
interpreted by a court of competent jurisdiction so that the
Partnership or any of its subsidiaries becomes taxable as a
corporation or otherwise subject to taxation as an entity for
federal, state or local income tax purposes, the managing
general partner may, in its sole discretion, reduce the minimum
quarterly distribution and the target distribution levels for
each quarter by multiplying each distribution level by a
fraction, the numerator of which is available cash for that
quarter (after deducting the managing general partners
estimate of the Partnerships aggregate liability for the
quarter for such income taxes payable by reason of such
legislation or interpretation) and the denominator of which is
the sum of available cash for that quarter plus the managing
general partners estimate of the Partnerships
aggregate liability for the quarter for such income taxes
payable by reason of such legislation or interpretation. To the
extent that the actual tax liability differs from the estimated
tax liability for any quarter, the difference will be accounted
for in subsequent quarters.
Non-IDR Surplus Amount.
There will be
no distributions paid on the IDRs until the aggregate
adjusted operating surplus (as described below)
generated by the Partnership during the period from
October 24, 2007 through December 31, 2009, or the
non-IDR surplus amount, has been distributed in respect of the
special units, or, following an initial public offering of the
Partnership, the common and subordinated units (if any are
issued). In addition, there will be no distributions paid on the
IDRs for so long as the Partnership or its subsidiaries are
guarantors under our Credit Facility.
Definition of Adjusted Operating
Surplus.
Adjusted operating surplus is
intended to reflect the cash generated from operations during a
particular period and therefore excludes the $60 million
basket included as a component of operating surplus,
net increases in working capital borrowings and net drawdowns of
reserves of cash generated in prior periods. Adjusted operating
surplus for any period generally means:
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operating surplus generated with respect to that period (which
does not include the $60 million basket described in the
first bullet point of the definition of operating surplus
above); less
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any net increase in working capital borrowings with respect to
that period; less
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any net reduction in cash reserves for operating expenditures
with respect to that period not relating to an operating
expenditure made with respect to that period; plus
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any net decrease in working capital borrowings with respect to
that period; plus
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any net increase in cash reserves for operating expenditures
with respect to that period to the extent required by any debt
instrument for the repayment of principal, interest or premium.
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If the Partnership consummates an initial offering, cash
received by the Partnership or its subsidiaries in respect of
accounts receivable existing as of the closing of such an
offering will be deemed to not be operating surplus and thus
will be disregarded when calculating adjusted operating surplus.
Distributions Prior to the Partnerships Initial
Offering (if any).
Prior to the
Partnerships initial offering (if any), quarterly
distributions of available cash from operating surplus (as
described below) will be paid solely in respect of the special
units until the non-IDR surplus amount has been distributed.
After the limitations described in Non-IDR
surplus amount no longer apply and prior to the
Partnerships initial offering (if any), quarterly
distributions of available cash from operating surplus will be
paid in the following manner: (1)
First
, to the
special units, until each special unit has received a total
quarterly distribution equal to $0.4313 (the first target
distribution), (2)
Second,
(i) 13% to the
managing general partner interest (in respect of the IDRs) and
(ii) 87% to the special units until each special unit has
received a total quarterly amount equal to $0.4688 (the second
target distribution), (3)
Third
, (i) 23% to the
managing general partner interest (in respect of the IDRs) and
(ii) 77% to the special units, until each special unit has
received a total quarterly amount equal to $0.5625 (the third
target distribution), and (4)
Thereafter
,
(i) 48% to the managing general partner interest (in
respect of the IDRs) and (ii) 52% to the special units.
Distributions from Capital
Surplus.
Capital surplus is generally
generated only by borrowings other than working capital
borrowings, sales of debt securities and equity interests, and
sales or other
234
dispositions of assets for cash, other than inventory, accounts
receivable and the other current assets sold in the ordinary
course of business or as part of normal retirements or
replacements of assets.
The Partnership will make distributions of available cash from
capital surplus, if any, in the following manner:
(1)
First
, to all unitholders, pro rata, until the
minimum quarterly distribution is reduced to zero, as described
below, (2)
Second
, to the common unitholders, if
any, pro rata, until the Partnership distributes for each common
unit an amount of available cash from capital surplus equal to
any unpaid arrearages in payment of the minimum quarterly
distribution on the common units, and
(3)
Thereafter
, the Partnership will make all
distributions of available cash from capital surplus as if they
were from operating surplus. The preceding discussion is based
on the assumptions that the Partnership does not issue
additional classes of equity interests.
The partnership agreement will treat a distribution of capital
surplus as the repayment of the consideration for the issuance
of a unit by the Partnership, which is a return of capital. Each
time a distribution of capital surplus is made, the minimum
quarterly distribution and the target distribution levels will
be reduced in the same proportion as the distribution had in
relation to the fair market value of the common units prior to
the announcement of the distribution. Because distributions of
capital surplus will reduce the minimum quarterly distribution,
after any of these distributions are made, it may be easier for
the managing general partner to receive incentive distributions
and for the subordinated units to convert into common units.
However, any distribution of capital surplus before the minimum
quarterly distribution is reduced to zero cannot be applied to
the payment of the minimum quarterly distribution or any
arrearages.
Once the Partnership reduces the minimum quarterly distribution
and the target distribution levels to zero, the Partnership will
then make all future distributions from operating surplus, with
52% being paid to the unitholders, pro rata, and 48% to the
Partnerships managing general partner.
Distributions of Cash Upon
Liquidation.
If the Partnership dissolves in
accordance with the partnership agreement, the Partnership will
sell or otherwise dispose of its assets in a process called
liquidation. The Partnership will first apply the proceeds of
liquidation to the payment of its creditors. The Partnership
will distribute any remaining proceeds to the unitholders and
the managing general partner, in accordance with their capital
account balances, as adjusted to reflect any gain or loss upon
the sale or other disposition of the Partnerships assets
in liquidation.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of units to a
repayment of the initial value contributed by the unitholder to
the Partnership for its units, which we refer to as the
initial unit price for each unit. With respect to
our special units, the initial unit price will be the value of
the nitrogen fertilizer business we contribute to the
Partnership, divided by the number of special units we receive.
The initial unit price for the common units issued by the
Partnership in the initial offering, if any, will be the price
paid for the common units. If there are common units and
subordinated units outstanding, the allocation is intended, to
the extent possible, to entitle the holders of common units to a
preference over the holders of subordinated units upon the
Partnerships liquidation, to the extent required to permit
common unitholders to receive their initial unit price plus the
minimum quarterly distribution for the quarter during which
liquidation occurs plus any unpaid arrearages in payment of the
minimum quarterly distribution on the common units. However,
there may not be sufficient gain upon the Partnerships
liquidation to enable the holders of units, including us, to
fully recover all of the initial unit price. Any further net
gain recognized upon liquidation will be allocated in a manner
that takes into account the incentive distribution rights of the
managing general partner.
The manner of the adjustment for gain is set forth in the
partnership agreement. If the Partnerships liquidation
occurs after the Partnerships initial offering, if any,
and before the end of the subordination period, the Partnership
will allocate any gain to the partners in the following manner:
(1)
First
, to the managing general partner and the
holders of units who have negative balances in their capital
accounts to the extent of and in proportion to those negative
balances, (2)
Second
, to the common unitholders, pro
rata, until the capital account for each common unit is equal to
the sum of (i) the initial unit price, (ii) the amount
of the minimum quarterly distribution for the quarter during
235
which the liquidation occurs, and (iii) any unpaid
arrearages in payment of the minimum quarterly distribution,
(3)
Third
, to the subordinated unitholders, pro
rata, until the capital account for each subordinated unit is
equal to the sum of (i) the initial unit price and
(ii) the amount of the minimum quarterly distribution for
the quarter during which the liquidation occurs,
(4)
Fourth
, to all unitholders, pro rata, until the
Partnership allocates under this paragraph an amount per unit
equal to (i) the sum of the excess of the first target
distribution per unit over the minimum quarterly distribution
per unit for each quarter of the Partnerships existence,
less (ii) the cumulative amount per unit of any
distributions of available cash from operating surplus in excess
of the minimum quarterly distribution per unit that the
Partnership distributed to the unitholders, pro rata, for each
quarter of the Partnerships existence,
(5)
Fifth
, 87% to all unitholders, pro rata, and 13%
to the managing general partner, until the Partnership allocates
under this paragraph an amount per unit equal to (i) the
sum of the excess of the second target distribution per unit
over the first target distribution per unit for each quarter of
the Partnerships existence; less the cumulative amount per
unit of any distributions of available cash from operating
surplus in excess of the first target distribution per unit that
the Partnership distributed 87% to the unitholders, pro rata,
and 13% to the managing general partner for each quarter of the
Partnerships existence, (6)
Sixth
, 77% to all
unitholders, pro rata, and 23% to the managing general partner,
until the Partnership allocates under this paragraph an amount
per unit equal to: (i) the sum of the excess of the third
target distribution per unit over the second target distribution
per unit for each quarter of the Partnerships existence,
less (ii) the cumulative amount per unit of any
distributions of available cash from operating surplus in excess
of the second target distribution per unit that the Partnership
distributed 77% to the unitholders, pro rata, and 23% to the
managing general partner for each quarter of the
Partnerships existence, and (7)
Thereafter
,
52% to all unitholders, pro rata, and 48% to the managing
general partner. The percentages set forth above are based on
the assumption that the Partnership has not issued additional
classes of equity interests.
If the liquidation occurs before the Partnerships initial
offering, the special units will receive allocations of gain in
the same manner as described above for the common units, except
that the distinction between common units and subordinated units
will not be relevant, so that subclause (iii) of
clause (2) above and all of clause (3) above will not
be applicable. If the liquidation occurs after the end of the
subordination period, the distinction between common units and
subordinated units will disappear, so that subclause (iii)
of clause (2) above and all of the third bullet point above
will no longer be applicable.
If the Partnerships liquidation occurs after the
Partnerships initial offering, if any, and before the end
of the subordination period, the Partnership will generally
allocate any loss to the managing general partner and the
unitholders in the following manner: (1)
First
, to
holders of subordinated units in proportion to the positive
balances in their capital accounts, until the capital accounts
of the subordinated unitholders have been reduced to zero,
(2)
Second
, to the holders of common units in
proportion to the positive balances in their capital accounts,
until the capital accounts of the common unitholders have been
reduced to zero, and (3)
Thereafter,
100% to the
managing general partner.
If the liquidation occurs before the Partnerships initial
offering, the special units will receive allocations of loss in
the same manner as described above for the common units, except
that the distinction between common units and subordinated units
will not be relevant, so that all of clause (1) above will
not be applicable. If the liquidation occurs after the end of
the subordination period, the distinction between common units
and subordinated units will disappear, so that all of
clause (1) will no longer be applicable.
Adjustments to Capital Accounts.
The
Partnership will make adjustments to capital accounts upon the
issuance of additional units. In doing so, the Partnership will
allocate any unrealized and, for tax purposes, unrecognized gain
or loss resulting from the adjustments to the unitholders and
the managing general partner in the same manner as the
Partnership allocates gain or loss upon liquidation. In the
event that the Partnership makes positive adjustments to the
capital accounts upon the issuance of additional units, the
Partnership will allocate any later negative adjustments to the
capital accounts resulting from the issuance of additional units
or upon the Partnerships liquidation in a manner which
results, to the extent possible, in the managing general
partners capital account
236
balances equaling the amount which they would have been if no
earlier positive adjustments to the capital accounts had been
made.
Withdrawal or
Removal of the Managing General Partner
Except as described below, the managing general partner has
agreed not to withdraw voluntarily as the Partnerships
managing general partner prior to June 30, 2017 without
obtaining the approval of the holders of at least a majority of
the outstanding units, excluding units held by the managing
general partner and its affiliates (including us), and
furnishing an opinion of counsel regarding limited liability and
tax matters. On or after June 30, 2017, the managing
general partner may withdraw as managing general partner without
first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of the partnership agreement.
Notwithstanding the information above, the managing general
partner may withdraw without unitholder approval upon
90 days notice to the unitholders if at least 50% of the
outstanding units are held or controlled by one person and its
affiliates other than the managing general partner and its
affiliates. In addition, the partnership agreement permits the
managing general partner in some instances to sell or otherwise
transfer all of its managing general partner interest without
the approval of the unitholders. See Transfer
of Managing General Partner Interest.
Upon withdrawal of the managing general partner under any
circumstances, other than as a result of a transfer by the
managing general partner of all or a part of its general partner
interest in the Partnership, the holders of a majority of the
outstanding classes of units voting as a single class may select
a successor to that withdrawing managing general partner. If a
successor is not elected, or is elected but an opinion of
counsel regarding limited liability and tax matters cannot be
obtained, the Partnership will be dissolved, wound up and
liquidated, unless within a specified period of time after that
withdrawal, the holders of a unit majority agree in writing to
continue the business of the Partnership and to appoint a
successor managing general partner. See
Termination and Dissolution.
The managing general partner may not be removed unless that
removal is approved by the vote of the holders of not less than
80% of the outstanding units, voting together as a single class,
including units held by the managing general partner and its
affiliates, and the Partnership receives an opinion of counsel
regarding limited liability and tax matters. Prior to
October 26, 2012, the managing general partner can only be
removed for cause. Any removal of the managing
general partner is also subject to the approval of a successor
managing general partner by the vote of the unitholders holding
a majority of each class of outstanding units, voting as
separate classes.
The partnership agreement also provides that if the managing
general partner is removed as managing general partner under
circumstances where cause does not exist and no units held by
us, including our subsidiary that holds the subordinated units
(if any) and our other affiliates, are voted in favor of that
removal, the subordination period will end and all outstanding
subordinated units will immediately convert into common units on
a one-for-one basis, and any existing arrearages in payment of
the minimum quarterly distribution on the common units will be
extinguished.
If the managing general partner is removed as managing general
partner under circumstances where cause does not exist and no
units held by the managing general partner and its affiliates
(which will include us until such time as we cease to be an
affiliate of the managing general partner) are voted in favor of
that removal, the managing general partner will have the right
to convert its managing general partner interest, including the
incentive distribution rights, into common units or to receive
cash in exchange for those interests based on the fair market
value of the interests at the time.
In the event of removal of the managing general partner under
circumstances where cause exists or withdrawal of the managing
general partner where that withdrawal violates the partnership
agreement, a successor managing general partner will have the
option to purchase the managing general partner interest,
including the IDRs, of the departing managing general partner
for a cash payment equal to the fair market value of the
managing general partner interest. Under all other circumstances
where the managing general partner withdraws or is removed, the
departing managing
237
general partner will have the option to require the successor
managing general partner to purchase the managing general
partner interest of the departing managing general partner for
its fair market value. In each case, this fair market value will
be determined by agreement between the departing managing
general partner and the successor managing general partner. If
no agreement is reached, an independent investment banking firm
or other independent expert selected by the departing managing
general partner and the successor managing general partner will
determine the fair market value. If the departing managing
general partner and the successor managing general partner
cannot agree upon an expert, then an expert chosen by agreement
of the experts selected by each of them will determine the fair
market value.
If the option described above is not exercised by either the
departing managing general partner or the successor managing
general partner, the departing managing general partners
general partner interest, including its IDRs, will automatically
convert into common units equal to the fair market value of
those interests as determined by an investment banking firm or
other independent expert selected in the manner described in the
preceding paragraph.
In addition, the Partnership will be required to reimburse the
departing managing general partner for all amounts due to it,
including, without limitation, all employee-related liabilities,
including severance liabilities, incurred for the termination of
any employees employed by the departing managing general partner
or its affiliates for the Partnerships benefit.
Voting
Rights
The partnership agreement provides that various matters require
the approval of a unit majority. A unit majority
requires (1) prior to the initial offering, the approval of
a majority of the special units; (2) during the
subordination period, the approval of a majority of the common
units, excluding those common units held by the managing general
partner and its affiliates (which will include us until such
time as we cease to be an affiliate of the managing general
partner), and a majority of the subordinated units, voting as
separate classes; and (3) after the subordination period,
the approval of a majority of the common units. In voting their
units, the Partnerships general partners and their
affiliates will have no fiduciary duty or obligation whatsoever
to the Partnership or the other partners, including any duty to
act in good faith or in the best interests of the Partnership
and its other partners.
The following is a summary of the vote requirements specified
for certain matters under the partnership agreement:
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Issuance of Additional Units:
no
approval right.
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Amendment of the Partnership
Agreement:
certain amendments may be made by
the managing general partner without the approval of the
unitholders. Other amendments generally require the approval of
a unit majority.
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Merger of the Partnership or the Sale of all or
Substantially all of the Partnerships
Assets:
unit majority in certain
circumstances. In addition, the holder of special GP rights has
joint management rights with respect to some mergers.
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Dissolution of the Partnership:
unit
majority.
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Continuation of the Partnership upon
Dissolution:
unit majority.
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Withdrawal of the Managing General
Partner:
under most circumstances, a unit
majority is required for the withdrawal of the managing general
partner prior to June 30, 2017 in a manner which would
cause a dissolution of the Partnership.
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Removal of the Managing General
Partner:
not less than 80% of the outstanding
units, voting as a single class, including units held by the
managing general partner and its affiliates (i) for cause
prior to October 26, 2012 or (ii) with or without
cause (as defined in the partnership agreement) on or after
October 26, 2012.
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Transfer of the Managing General Partners General
Partner Interest:
the managing general
partner may transfer all, but not less than all, of its managing
general partner interest
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238
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in the Partnership without a vote of any unitholders and without
our approval, to an affiliate or to another person (other than
an individual) in connection with its merger or consolidation
with or into, or sale of all or substantially all of its assets
to, such person. The approval of a majority of the outstanding
units, excluding units held by the managing general partner and
its affiliates, voting as a class, and our approval, is required
in other circumstances for a transfer of the managing general
partner interest to a third party prior to October 26, 2017.
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Transfer of Ownership Interests in the Managing General
Partner:
no approval required at any time.
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Issuance of
Additional Partnership Interests
The partnership agreement authorizes the Partnership to issue an
unlimited number of additional partnership interests for the
consideration and on the terms and conditions determined by the
managing general partner without the approval of the
unitholders, subject to the special GP rights with respect to
the issuance of equity with rights to distribution or in
liquidation ranking prior to or senior to the common units.
Upon issuance of additional partnership interests, the
Partnerships managing general partner will have the right,
which it may from time to time assign in whole or in part to any
of its affiliates, to purchase common units, subordinated units
or other partnership interests whenever, and on the same terms
that, the Partnership issues those interests to persons other
than the managing general partner and its affiliates, to the
extent necessary to maintain its and its affiliates
percentage interest, including such interest represented by
common units and subordinated units, that existed immediately
prior to each issuance. We will have similar rights to purchase
common units, subordinated units or other partnership interests
from the Partnership, except that our rights will not apply to
any issuance of interests by the Partnership in its initial
offering. For the purpose of these rights, we and the managing
general partner shall be deemed not to be affiliates of one
another, unless we otherwise agree. Other holders of units will
not have preemptive rights to acquire additional common units or
other partnership interests unless they are granted those rights
in connection with the issuance of their units by the
Partnership.
Amendment of
the Partnership Agreement
General.
Amendments to the partnership
agreement may be proposed only by the managing general partner.
However, the managing general partner has no duty or obligation
to propose any amendment and may decline to do so free of any
fiduciary duty or obligation whatsoever to the Partnership or
any partner, including any duty to act in good faith or in the
best interests of the Partnership or the limited partners. In
order to adopt a proposed amendment, other than the amendments
discussed below, the managing general partner is required to
seek written approval of the holders of the number of units
required to approve the amendment or call a meeting of the
limited partners to consider and vote upon the proposed
amendment. Except as described below, an amendment must be
approved by a unit majority.
Prohibited Amendments.
No amendment may
be made that would: (1) enlarge the obligations of any
limited partner or us, as a general partner, without its
consent, unless approved by at least a majority of the type or
class of partner interests so affected or (2) enlarge the
obligations of, or restrict in any way any action by or rights
of, or reduce in any way the amounts distributable, reimbursable
or otherwise payable by the Partnership to any general partner
or any of its affiliates without its consent, which may be given
or withheld in its sole discretion. The provision of the
partnership agreement preventing the amendments having the
effects described in any of the clauses above can be amended
upon the approval of the holders of at least 90% of the
outstanding units, voting together as a single class (including
units owned by the managing general partner and its affiliates).
As of December 31, 2007, we own all of the outstanding
units.
No Unitholder Approval.
The managing
general partner may generally make amendments to the partnership
agreement without the approval of any unitholders to reflect
(1) a change in the Partnerships name, the location
of its principal place of business, its registered agent or its
registered
239
office, (2) the admission, substitution, withdrawal or
removal of partners in accordance with the partnership
agreement, (3) a change that the managing general partner
determines to be necessary or appropriate for the Partnership to
qualify or to continue its qualification as a limited
partnership or a partnership in which the limited partners have
limited liability under the laws of any state or to ensure that
neither the Partnership nor any of its subsidiaries will be
treated as an association taxable as a corporation or otherwise
taxed as an entity for federal income tax purposes (to the
extent not already so treated or taxed), (4) an amendment
that is necessary, in the opinion of the Partnerships
counsel, to prevent the Partnership or its general partners or
their directors, officers, agents, or trustees from in any
manner being subjected to the provisions of the Investment
Company Act of 1940, the Investment Advisers Act of 1940, or
plan asset regulations adopted under the Employee
Retirement Income Security Act of 1974 (ERISA),
whether or not substantially similar to plan asset regulations
currently applied or proposed, (5) an amendment that the
managing general partner determines to be necessary or
appropriate for the authorization of additional partnership
interests or rights to acquire partnership interests, as
otherwise permitted by the partnership agreement, (6) any
amendment expressly permitted in our partnership agreement to be
made by the Partnerships managing general partner acting
alone, (7) an amendment effected, necessitated or
contemplated by a merger agreement that has been approved under
the terms of the partnership agreement, (8) any amendment
that the Partnerships managing general partner determines
to be necessary or appropriate for the formation by the
Partnership of, or its investment in, any corporation,
partnership or other entity, as otherwise permitted by the
partnership agreement, (9) a change in the
Partnerships fiscal year or taxable year and related
changes, (10) mergers with or conveyances to another
limited liability entity that is newly formed and has no assets,
liabilities or operations at the time of the merger or
conveyance other than those it receives by way of the merger or
conveyance or (11) any other amendments substantially
similar to any of the matters described above.
In addition, the managing general partner may make amendments to
the partnership agreement without the approval of any partner if
the managing general partner determines that those amendments
(1) do not adversely affect in any material respect the
partners (considered as a whole or any particular class of
partners), (2) are necessary or appropriate to satisfy any
requirements, conditions, or guidelines contained in any
opinion, directive, order, ruling, or regulation of any federal
or state agency or judicial authority or contained in any
federal or state statute, (3) are necessary or appropriate
to facilitate the trading of limited partner interests or to
comply with any rule, regulation, guideline, or requirement of
any securities exchange on which the limited partner interests
are or will be listed for trading, (4) are necessary or
appropriate for any action taken by the managing general partner
relating to splits or combinations of units under the provisions
of the partnership agreement or (5) are required to effect
the intent of the provisions of the partnership agreement or are
otherwise contemplated by the partnership agreement.
Opinion of Counsel and Unitholder
Approval.
For amendments of the type not
requiring unitholder approval, the managing general partner will
not be required to obtain an opinion of counsel that an
amendment will not result in a loss of limited liability to the
limited partners or result in the Partnership being treated as
an entity for federal income tax purposes in connection with any
of the amendments. No other amendments to the partnership
agreement will become effective without the approval of holders
of at least 90% of the outstanding units voting as a single
class unless the managing general partner first obtains an
opinion of counsel to the effect that the amendment will not
affect the limited liability under Delaware law of any of the
Partnerships limited partners. Finally, the managing
general partner may consummate any merger without the prior
approval of the Partnerships unitholders if the
Partnership is the surviving entity in the transaction, the
transaction would not result in any amendment to the partnership
agreement (other than an amendment that the managing general
partner could adopt without the consent of other partners), each
of the units outstanding immediately prior to the merger will be
an identical unit of the Partnership following the transaction,
the units to be issued do not exceed 20% of the outstanding
units immediately prior to the transaction and the managing
general partner has received an opinion of counsel regarding
certain limited liability and tax matters.
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In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected. Any
amendment that reduces the voting percentage required to take
any action must be approved by the affirmative vote of partners
whose aggregate outstanding units constitute not less than the
voting requirement sought to be reduced.
Merger, Sale
or Other Disposition of Assets
A merger or consolidation of the Partnership requires the prior
consent of the managing general partner. However, the managing
general partner will have no duty or obligation to consent to
any merger or consolidation and may decline to do so free of any
fiduciary duty or obligation whatsoever to the Partnership or
other partners, including any duty to act in good faith or in
the best interest of the Partnership or the other partners. We
also have joint management rights with respect to certain
mergers. Mergers and consolidations generally also require the
affirmative vote or consent of the holders of a unit majority,
unless the merger agreement contains any provision that, if
contained in an amendment to the partnership agreement, would
require for its approval the vote or consent of a greater
percentage of the outstanding units or of any class of partners,
in which case such greater percentage vote or consent shall be
required.
In addition, the partnership agreement generally prohibits the
managing general partner, without the prior approval of the
holders of units representing a unit majority, from causing the
Partnership to, among other things, sell, exchange or otherwise
dispose of all or substantially all of the Partnerships
assets in a single transaction or a series of related
transactions, including by way of merger, consolidation or other
combination, or approving on the Partnerships behalf the
sale, exchange or other disposition of all or substantially all
of the assets of the Partnerships subsidiaries. The
managing general partner may, however, mortgage, pledge,
hypothecate or grant a security interest in all or substantially
all of the Partnerships assets without that approval. The
managing general partner may also sell all or substantially all
of the Partnerships assets under a foreclosure or other
realization upon those encumbrances without that approval.
If the conditions specified in the partnership agreement are
satisfied, the managing general partner may, without other
partner approval, convert the Partnership or any of its
subsidiaries into a new limited liability entity or merge the
Partnership or any of its subsidiaries into, or convey some or
all of its assets to, a newly formed entity if the sole purpose
of that merger or conveyance is to effect a mere change in its
legal form into another limited liability entity, the governing
instruments of the new entity provide the limited partners and
general partners with the same rights and obligations as
contained in the partnership agreement and the Partnership
receives an opinion of counsel regarding certain limited
liability and tax matters. The unitholders are not entitled to
dissenters rights of appraisal under the partnership
agreement or applicable Delaware law in the event of a
conversion, merger or consolidation, a sale of substantially all
of the Partnerships assets or any other transaction or
event.
Termination
and Dissolution
The Partnership will continue as a limited partnership until
terminated under the partnership agreement. The Partnership will
dissolve upon: (1) the election of the managing general
partner to dissolve the Partnership, if approved by the holders
of units representing a unit majority; (2) there being no
limited partners, unless the Partnership continues without
dissolution in accordance with applicable Delaware law;
(3) the entry of a decree of judicial dissolution of the
Partnership or (4) the withdrawal or removal of the
managing general partner or any other event that results in its
ceasing to be the Partnerships managing general partner
other than by reason of a transfer of its managing general
partner interest in accordance with the partnership agreement or
withdrawal or removal following approval and admission of a
successor.
Upon a dissolution under clause (4) above, the holders of a
unit majority may also elect, within specific time limitations,
to continue the Partnerships business on the same terms
and conditions described in the partnership agreement by
appointing as a successor managing general partner an
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entity approved by the holders of units representing a unit
majority, subject to receipt of an opinion of counsel to the
effect that (1) the action would not result in the loss of
limited liability under Delaware law of any limited partner and
(2) neither the Partnership nor any of its subsidiaries
would be treated as an association taxable as a corporation or
otherwise be taxable as an entity for federal income tax
purposes upon the exercise of that right to continue (to the
extent not already so treated or taxed).
Upon dissolution of the Partnership, unless the business of the
Partnership is continued, the liquidator authorized to wind up
the Partnerships affairs will, acting with all of the
powers of the managing general partner that are necessary or
appropriate, liquidate the Partnerships assets and apply
the proceeds of the liquidation as described in the partnership
agreement. The liquidator may defer liquidation or distribution
of the Partnerships assets for a reasonable period of time
or distribute assets to partners in kind if it determines that a
sale would be impractical or would cause undue loss to the
partners.
Transfer of
Managing General Partner Interest
Except for the transfer by the managing general partner of all,
but not less than all, of its managing general partner interest
in the Partnership to (1) an affiliate of the managing
general partner (other than an individual) or (2) another
entity as part of the merger or consolidation of the managing
general partner with or into another entity or the transfer by
the managing general partner of all or substantially all of its
assets to another entity, the managing general partner may not
transfer all or any part of its managing general partner
interest in the Partnership to another person prior to
October 26, 2017 without the approval of both (1) the
holders of at least a majority of the outstanding units
(excluding units held by the managing general partner and its
affiliates) and (2) us. On or after October 26, 2017,
the managing general partner interest will be freely
transferable. As a condition of any transfer, the transferee
must, among other things, assume the rights and duties of the
managing general partner, agree to be bound by the provisions of
the partnership agreement and furnish an opinion of counsel
regarding limited liability and tax matters. The
Partnerships general partners and their affiliates may at
any time transfer units to one or more persons, without
unitholder approval, except that they may not transfer
subordinated units to the Partnership.
Transfer of
Ownership Interests in the Managing General
Partner
At any time, the owners of the managing general partner may sell
or transfer all or part of their ownership interests in the
managing general partner to an affiliate or a third party
without the approval of the Partnerships unitholders.
Change of
Management Provisions
The partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove the managing general partner as the managing general
partner of the Partnership or otherwise change the
Partnerships management. If any person or group other than
the managing general partner and its affiliates (including us)
acquires beneficial ownership of 20% or more of any class of
units, that person or group loses voting rights on all of its
units. This loss of voting rights does not apply to any person
or group that acquires the units from the managing general
partner or its affiliates and any transferees of that person or
group approved by the managing general partner or to any person
or group who acquires the units with the prior approval of the
board of directors of the managing general partner.
The partnership agreement also provides that if the
Partnerships managing general partner is removed without
cause and no units held by us, our subsidiary that holds the
subordinated units (if any) and our other affiliates are voted
in favor of that removal, the subordination period will end and
all outstanding subordinated units will immediately convert into
common units on a one-for-one basis; and any existing arrearages
in payment of the minimum quarterly distribution on the common
units will be extinguished.
If the managing general partner is removed as managing general
partner under circumstances where cause does not exist and no
units held by the managing general partner and its affiliates
(which
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will include us until such time as we cease to be an affiliate
of the managing general partner) are voted in favor of that
removal, the managing general partner will have the right to
convert its managing general partner interest, including its
incentive distribution rights, into common units or to receive
cash in exchange for the managing general partner interest.
Limited Call
Right
If at any time the managing general partner and its affiliates
own more than 80% of the then-issued and outstanding limited
partner interests of any class, the managing general partner
will have the right, which it may assign in whole or in part to
any of its affiliates or to the Partnership, to acquire all, but
not less than all, of the limited partner interests of the class
held by unaffiliated persons, as of a record date to be selected
by the managing general partner, on at least 10 but not more
than 60 days notice. The purchase price in the event
of such an acquisition will be the greater of (1) the
highest price paid by the managing general partner or any of its
affiliates for any limited partner interests of the class
purchased within the 90 days preceding the date on which
the managing general partner first mails notice of its election
to purchase those limited partner interests, and (2) the
average of the daily closing prices of the limited partner
interests over the 20 trading days preceding the date three days
before notice of exercise of the call right is first mailed. At
any time following the Partnerships initial offering, if
any, if we fail to hold at least 20% of the units of the
Partnership our common GP units will be deemed to be part of the
same class of partnership interests as the common LP units for
purposes of this provision. This provision will make it easier
for the managing general partner to take the Partnership private
in its discretion.
Indemnification
Under the partnership agreement, the Partnership will indemnify
the following persons in most circumstances, to the fullest
extent permitted by law, from and against all losses, claims,
damages, liabilities, joint or several, expenses (including
legal fees and expenses), judgments, fines, penalties, interest,
settlements or other amounts arising from any and all
threatened, pending or completed claims, demands, actions suits
or proceedings: (1) the Partnerships general
partners; (2) any departing general partner; (3) any
person who is or was a director, officer, fiduciary, trustee,
manager or managing member of the Partnership or any of the
Partnerships subsidiaries, its general partners or any
departing general partner; (4) any person who is or was
serving as a director, officer, fiduciary, trustee, manager or
managing member of another person owing a fiduciary duty to the
Partnership or any of its subsidiaries at the request of a
general partner or any departing general partner; (5) any
person who controls a general partner; or (6) any person
designated by the Partnerships managing general partner.
Any indemnification under these provisions will only be out of
the Partnerships assets. Unless they otherwise agree, the
Partnerships general partners will not be personally
liable for, or have any obligation to contribute or loan funds
or assets to the Partnership to enable the Partnership to
effectuate, indemnification. The Partnership may purchase
insurance against liabilities asserted against and expenses
incurred by persons for its activities, regardless of whether it
would have the power to indemnify the person against liabilities
under the partnership agreement.
Reimbursement
of Expenses
The partnership agreement requires the Partnership to reimburse
the Partnerships managing general partner for (1) all
direct and indirect expenses it incurs or payments it makes on
behalf of the Partnership (including salary, bonus, incentive
compensation and other amounts paid to any person, including
affiliates of the managing general partner, to perform services
for the Partnership or for the managing general partner in the
discharge of its duties to the Partnership) and (2) all
other expenses allocable to the Partnership or otherwise
incurred by the managing general partner in connection with
operating the Partnerships business (including expenses
allocated to the managing general partner by its affiliates).
The managing general partner is entitled to determine the
expenses that are allocable to the Partnership.
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Conflicts of
Interest
Conflicts of interest exist and may arise in the future as a
result of (1) the overlap of directors and officers between
us and the Partnerships managing general partner, which
may result in conflicting obligations by our directors and
officers, (2) duties of the Partnerships managing
general partner to act for the benefit of its owners, which may
conflict with our interests and the interests of our
stockholders, and (3) our duties as a general partner of
the Partnership to act for the benefit of all unit holders,
including future unaffiliated partners, which may conflict with
our interests and the interests of our stockholders. The
directors and officers of the Partnerships managing
general partner, Fertilizer GP, have fiduciary duties to manage
Fertilizer GP in a manner beneficial to its owners, but at the
same time, Fertilizer GP has a fiduciary duty to manage the
Partnership in a manner beneficial to its unit holders,
including us. In addition, because we are a general partner of
the Partnership, we have a legal duty to exercise our special GP
rights in a manner beneficial to the Partnerships unit
holders, who may in the future include unaffiliated partners,
but at the same time our directors and officers have a fiduciary
duty to act in a manner beneficial to us and our stockholders.
With respect to conflicts of interest between the Partnership
and Fertilizer GP, Fertilizer GP will resolve that conflict. The
partnership agreement will permit the board of directors of the
managing general partner to establish a conflicts committee. See
Management of the Partnership. The
partnership agreement contains provisions that modify and limit
the fiduciary duties of Fertilizer GP and us to the unit
holders. The partnership agreement also restricts the remedies
available to unit holders (including us) for actions taken that,
without those limitations, might constitute breaches of
fiduciary duty.
Fertilizer GP, as the managing general partner, will not be in
breach of its obligations under the partnership agreement or its
duties to the Partnership or its unit holders (including us) if
the resolution of the conflict is:
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approved by Fertilizer GPs conflicts committee, although
Fertilizer GP is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by Fertilizer GP and its
affiliates (including us so long as we remain an affiliate);
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on terms no less favorable to the Partnership than those
generally being provided to or available from unrelated third
parties; or
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fair and reasonable to the Partnership, taking into account the
totality of the relationships between the parties involved,
including other transactions that may be particularly favorable
or advantageous to the Partnership.
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Fertilizer GP may, but is not required to, seek approval from
the conflicts committee of its board of directors or from the
common unit holders. If Fertilizer GP does not seek approval
from the conflicts committee and its board of directors
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third and fourth bullet points above,
then it will be presumed that, in making its decision, the board
of directors acted in good faith, and in any proceeding brought
by or on behalf of any partner or the Partnership, the person
bringing or prosecuting such proceeding will have the burden of
overcoming such presumption. Unless the resolution of a conflict
is specifically provided for in the partnership agreement,
Fertilizer GP or the conflicts committee may consider any
factors it determines in good faith to consider when resolving a
conflict. When the partnership agreement requires someone to act
in good faith, it requires that person to reasonably believe
that he is acting in the best interests of the Partnership,
unless the context otherwise requires.
Conflicts of interest could arise in the situations described
below, among others.
Fertilizer GP
Holds all of the Incentive Distribution Rights in the
Partnership.
Fertilizer GP, as managing general partner of the Partnership,
holds all of the incentive distribution rights in the
Partnership. Incentive distribution rights will give Fertilizer
GP a right to
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increasing percentages of the Partnerships quarterly
distributions from operating surplus after the aggregate
adjusted operating surplus generated by the Partnership during
the period from October 24, 2007 through December 31,
2009 has been distributed in respect of the special units
and/or
the
common and subordinated units. Fertilizer GP may have an
incentive to manage the Partnership in a manner which increases
these future cash flows rather than in a manner which increases
current cash flows. See Risk Factors Risks
Related to the Limited Partnership Structure Through Which We
Hold Our Interest in the Nitrogen Fertilizer
Business The managing general partner of the
Partnership has a fiduciary duty to favor the interests of its
owners, and these interests may differ from, or conflict with,
our interests and the interests of our stockholders.
Officers and
Directors of Fertilizer GP also Serve as Officers and Directors
of us and have Obligations to Both the Partnership and our
Business.
All of the executive officers and five of the seven directors of
Fertilizer GP also serve as directors and executive officers of
CVR Energy. We have entered into a services agreement with
Fertilizer GP and the Partnership pursuant to which our
executive officers and other employees provide services to the
Partnership. The executive officers who work for both us and
Fertilizer GP, including chief executive officer, chief
operating officer, chief financial officer, general counsel,
fertilizer general manager, and vice president for
environmental, health and safety, will divide their time between
our business and the business of the Partnership. These
directors and executive officers will face conflicts of
interests from time to time in making decisions that may benefit
either our company or the Partnership. When making decisions on
behalf of Fertilizer GP they will have to take into account the
interests of the Partnership and not of us.
The Owners of
the Partnerships Managing General Partner may Compete with
us or the Partnership or own Businesses that Compete with us or
the Partnership.
The owners of Fertilizer GP, which are our controlling
stockholders and senior management, are permitted to compete
with us or the Partnership or to own businesses that compete
with us or the Partnership. In addition, the owners of
Fertilizer GP are not required to share business opportunities
with us or the Partnership. See Risk Factors
Risks Related to the Limited Partnership Structure Through Which
We Hold Our Interest in the Nitrogen Fertilizer
Business The managing general partner of the
Partnership has a fiduciary duty to favor the interests of its
owners, and these interests may differ from, or conflict with,
our interests and the interests of our stockholders.
Fertilizer GP
is Allowed to take Into Account the Interests of Parties other
than the Partnership in Resolving Conflicts.
The partnership agreement contains provisions that reduce the
standards to which its general partners would otherwise be held
by state fiduciary duty law. For example, the partnership
agreement permits Fertilizer GP to make a number of decisions in
its individual capacity, as opposed to its capacity as managing
general partner. This entitles Fertilizer GP to consider only
the interests and factors that it desires, and it has no duty or
obligation to give any consideration to any interest of, or
factors affecting, the Partnership, the Partnerships
affiliates or any partner. Examples include the exercise of
Fertilizer GPs call right and the determination of whether
to consent to any merger or consolidation of the Partnership.
Fertilizer GP
has Limited its Liability and Reduced its Fiduciary Duties, and
has also Restricted the Remedies Available to the
Partnerships unit Holders (Including us) for Actions that,
without the Limitations, might Constitute Breaches of Fiduciary
Duty.
In addition to the provisions described above, the partnership
agreement contains provisions that restrict the remedies
available to the Partnerships unit holders for actions
that might otherwise constitute breaches of fiduciary duty. For
example:
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The partnership agreement provides that Fertilizer GP shall not
have any liability to the Partnership or its unit holders
(including us) for decisions made in its capacity as managing
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general partner so long as it acted in good faith, meaning it
believed that the decision was in the best interests of the
Partnership.
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The partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
approved by the conflicts committee of the board of directors of
Fertilizer GP and not involving a vote of unit holders must be
on terms no less favorable to the Partnership than those
generally being provided to or available from unrelated third
parties or be fair and reasonable to the
Partnership, as determined by Fertilizer GP in good faith, and
that, in determining whether a transaction or resolution is
fair and reasonable, Fertilizer GP may consider the
totality of the relationships between the parties involved,
including other transactions that may be particularly
advantageous or beneficial to the Partnership.
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The partnership agreement provides that Fertilizer GP and its
officers and directors will not be liable for monetary damages
to the Partnership or its partners for any acts or omissions
unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that
the general partner or its officers or directors acted in bad
faith or engaged in fraud or willful misconduct.
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Actions taken
by Fertilizer GP may Affect the Amount of Cash Distributions to
Unit Holders.
The amount of cash that is available for distribution to unit
holders, including us, is affected by decisions of Fertilizer GP
regarding such matters as:
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amount and timing of asset purchases and sales;
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cash expenditures;
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borrowings;
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issuance of additional units; and
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the creation, reduction, or increase of reserves in any quarter.
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In addition, borrowings by the Partnership and its affiliates do
not constitute a breach of any duty owed by Fertilizer GP to the
Partnerships unit holders, including us, including
borrowings that have the purpose or effect of enabling
Fertilizer GP to receive distributions on the incentive
distribution rights.
Contracts
between the Partnership, on the one Hand, and Fertilizer GP, on
the other, will not be the Result of Arms-Length
Negotiations.
The partnership agreement allows the Partnerships managing
general partner to determine, in good faith, any amounts to pay
itself for any services rendered to the Partnership. Neither the
partnership agreement nor any of the other agreements, contracts
and arrangements between the Partnership and the managing
general partner are or will be the result of arms-length
negotiations.
The partnership agreement generally provides that any affiliated
transaction, such as an agreement, contract or arrangement among
the Partnership and its general partners and their affiliates,
must be:
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on terms no less favorable to the Partnership than those
generally being provided to or available from unrelated third
parties; or
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fair and reasonable to the Partnership, taking into
account the totality of the relationships between the parties
involved (including other transactions that may be particularly
favorable or advantageous to the Partnership).
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Fertilizer GP
Intends to Limit the Liability of the Partnerships General
Partners Regarding the Partnerships
Obligations.
Fertilizer GP intends to limit the liability of the
Partnerships general partners under contractual
arrangements so that the contract counterparties have recourse
only to the Partnerships assets and not against the
Partnerships general partners or their assets. The
partnership agreement provides
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that any action taken by Fertilizer GP to limit the general
partners liability or the Partnerships liability is
not a breach of Fertilizer GPs fiduciary duties, even if
the Partnership could have obtained terms that are more
favorable without the limitation on liability.
The
Partnership may Choose not to Retain Separate Counsel for
Itself.
The attorneys, independent accountants and others who perform
services for the Partnership will be retained by Fertilizer GP
or its affiliates. Attorneys, independent accountants and others
who perform services for the Partnership are selected by
Fertilizer GP or the conflicts committee and may perform
services for Fertilizer GP and its affiliates. Fertilizer GP may
cause the Partnership to retain separate counsel for itself in
the event of a conflict of interest between a general partner
and its affiliates, on the one hand, and the Partnership or the
holders of common units, on the other, depending on the nature
of the conflict, although it does not intend to do so in most
cases.
Fertilizer GP,
as Managing General Partner, has the Power and Authority to
Conduct the Partnerships Business (Subject to our
Specified Joint Management Rights).
Under the partnership agreement, Fertilizer GP, as managing
general partner, has full power and authority to do all things,
other than those items that require unit holder approval or our
approval or with respect to which it has sought conflicts
committee approval, on such terms as it determines to be
necessary or appropriate to conduct the Partnerships
business including, but not limited to, the following (subject
to our specified joint management rights):
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the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of, or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible into
securities of the Partnership, and the incurring of any other
obligations;
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the making of tax, regulatory and other filings, or rendering of
periodic or other reports to governmental or other agencies
having jurisdiction over the Partnerships business or
assets;
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the acquisition, disposition, mortgage, pledge, encumbrance,
hypothecation or exchange of any or all of the
Partnerships assets or the merger or other combination of
the Partnership with or into another person;
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the negotiation, execution and performance of any contracts,
conveyances or other instruments;
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the distribution of Partnership cash;
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the selection and dismissal of employees and agents, outside
attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of
employment or hiring;
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the maintenance of insurance for the Partnerships benefit
and the benefit of its partners;
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the formation of, or acquisition of an interest in, and the
contribution of property and the making of loans to, any further
limited or general partnerships, joint ventures, corporations,
limited liability companies or other relationships;
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the control of any matters affecting the Partnerships
rights and obligations, including the bringing and defending of
actions at law or in equity and otherwise engaging in the
conduct of litigation, arbitration or mediation and the
incurring of legal expense and the settlement of claims and
litigation;
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the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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the purchase, sale or other acquisition or disposition of
Partnership interests, or the issuance of additional options,
rights, warrants and appreciation rights relating to Partnership
interests; and
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the entering into of agreements with any affiliates to render
services to the Partnership or to itself in the discharge of its
duties as the Partnerships managing general partner.
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The
Partnership Agreement Limits the Fiduciary Duties of the
Managing General Partner to the Partnership and to other Unit
Holders.
The Partnerships general partners are accountable to the
Partnership and its unit holders as a fiduciary. Fiduciary
duties owed to unit holders by the general partners are
prescribed by law and the partnership agreement. The Delaware
Limited Partnership Act provides that Delaware limited
partnerships may, in their partnership agreements, restrict or
expand the fiduciary duties owed by the general partner to other
partners and the partnership.
The partnership agreement contains various provisions
restricting the fiduciary duties that might otherwise be owed by
Fertilizer GP. The Partnership has adopted these provisions to
allow the Partnerships general partners or their
affiliates to engage in transactions with the Partnership that
would otherwise be prohibited by state law fiduciary standards
and to take into account the interests of other parties in
addition to the Partnerships interests when resolving
conflicts of interest. Without such modifications, such
transactions could result in violations of the
Partnerships general partners state law fiduciary
duty standards. We believe this is appropriate and necessary
because (1) the board of directors of Fertilizer GP, the
Partnerships managing general partner, has both fiduciary
duties to manage the Partnerships managing general partner
in a manner beneficial to its owners and fiduciary duties to
manage the Partnership in a manner beneficial to unit holders
(including CVR Energy) and (2) we, in our capacity of
general partner, have both duties to exercise our special GP
rights in a manner beneficial to our stockholders and fiduciary
duties to exercise such rights in a manner beneficial to all of
the Partnerships unit holders. Without these
modifications, the Partnerships general partners
ability to make decisions involving conflicts of interest would
be restricted. The modifications to the fiduciary standards
enable the Partnerships general partners to take into
consideration all parties involved in the proposed action. These
modifications disadvantage the unit holders because they
restrict the rights and remedies that would otherwise be
available to unit holders for actions that, without those
limitations, might constitute breaches of fiduciary duty, as
described below, and permit the Partnerships general
partners to take into account the interests of third parties in
addition to the Partnerships interests when resolving
conflicts of interest.
The following is a summary of the material restrictions of the
fiduciary duties owed by the general partners:
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State law fiduciary duty standards are generally considered to
include an obligation to act in good faith and with due care and
loyalty. The duty of care, in the absence of a provision in a
partnership agreement providing otherwise, would generally
require a general partner to act for the partnership in the same
manner as a prudent person would act on his own behalf. The duty
of loyalty, in the absence of a provision in a partnership
agreement providing otherwise, would generally prohibit a
general partner of a Delaware limited partnership from taking
any action or engaging in any transaction where the general
partner has a conflict of interest.
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The partnership agreement contains provisions that waive or
consent to conduct by the Partnerships general partners
and their affiliates that might otherwise raise issues as to
compliance with fiduciary duties or applicable law. For example,
the partnership agreement provides that when either of the
general partners is acting in its capacity as a general partner,
as opposed to in its individual capacity, it must act in
good faith and will not be subject to any other
standard under applicable law. In addition, when either of the
general partners is acting in its individual capacity, as
opposed to in its capacity as a general partner, it may act
without any fiduciary obligation to the Partnership or the unit
holders whatsoever. These standards reduce the obligations to
which the Partnerships general partners would otherwise be
held.
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The partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
involving a vote of unit holders and that are not approved by
the conflicts committee of the board of directors of the
Partnerships managing general partner
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must be (1) on terms no less favorable to the Partnership
than those generally being provided to or available from
unrelated third parties or (2) fair and
reasonable to the Partnership, taking into account the
totality of the relationships between the parties involved
(including other transactions that may be particularly favorable
or advantageous to the Partnership).
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If the Partnerships managing general partner does not seek
approval from the conflicts committee or the common unit holders
and its board of directors determines that the resolution or
course of action taken with respect to the conflict of interest
satisfies either of the standards set forth in the bullet point
above, then it will be presumed that, in making its decision,
the board of directors of the managing general partner, which
may include board members affected by the conflict of interest,
acted in good faith, and in any proceeding brought by or on
behalf of any partner or the partnership, the person bringing or
prosecuting such proceeding will have the burden of overcoming
such presumption. These standards reduce the obligations to
which the Partnerships managing general partner would
otherwise be held.
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In addition to the other more specific provisions limiting the
obligations of the Partnerships general partners, the
partnership agreement further provides that the
Partnerships general partners and their officers and
directors will not be liable for monetary damages to the
Partnership or its partners for errors of judgment or for any
acts or omissions unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that the general partner or its officers and
directors acted in bad faith or engaged in fraud or willful
misconduct.
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Under the partnership agreement, the Partnership will indemnify
its general partners and their respective officers, directors
and managers, to the fullest extent permitted by law, against
liabilities, costs and expenses incurred by such general
partners or these other persons. The Partnership must provide
this indemnification unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that these persons acted in bad faith or engaged in
fraud or willful misconduct. The Partnership also must provide
this indemnification for criminal proceedings unless the general
partner or these other persons acted with knowledge that their
conduct was unlawful. Thus, the Partnerships general
partners could be indemnified for their negligent acts if they
meet the requirements set forth above. To the extent that these
provisions purport to include indemnification for liabilities
arising under the Securities Act, in the opinion of the SEC such
indemnification is contrary to public policy and therefore
unenforceable. See Risk Factors Risks Related
to the Limited Partnership Structure Through Which We Hold Our
Interest in the Nitrogen Fertilizer Business The
partnership agreement limits the fiduciary duties of the
managing general partner and restricts the remedies available to
us for actions taken by the managing general partner that might
otherwise constitute breaches of fiduciary duty.
Intercompany
Agreements
In connection with the formation of the Partnership, we entered
into several other agreements with the Partnership which govern
the business relations among us, the Partnership and the
managing general partner.
Feedstock and
Shared Services Agreement
In October 2007, we entered into a feedstock and shared services
agreement with the Partnership under which we and the
Partnership agreed to provide feedstock and other services to
each other. These feedstocks and services are utilized in the
respective production processes of our refinery and the nitrogen
fertilizer plant. Feedstocks provided under the agreement
include, among others, hydrogen, high-pressure steam, nitrogen,
instrument air, oxygen and natural gas.
The Partnership is obligated to provide us with hydrogen from
time to time. The agreement provides hydrogen supply and pricing
terms for circumstances where the refinery requires more
hydrogen than it can generate. Although we expect that the
Partnership will continue to provide hydrogen to us for at least
the rest of 2008 as it has done in prior years, we believe that
the
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Partnerships provision of hydrogen to our petroleum
operations will decrease, to some extent, during 2008 because
our new continuous catalytic reformer will produce hydrogen for
us. Also, we expect that a project under consideration will
further reduce the Partnerships hydrogen sales to our
refinery.
The agreement provides that both parties must deliver
high-pressure steam to one another under certain circumstances.
The Partnership must make available to us any high-pressure
steam produced by the nitrogen fertilizer plant that is not
required for the operation of the nitrogen fertilizer plant. We
must use commercially reasonable efforts to provide
high-pressure steam to the Partnership for purposes of allowing
the Partnership to commence and recommence operation of the
nitrogen fertilizer plant from time to time, and also for use at
the Linde air separation plant adjacent to our own facility. We
are not required to provide such high-pressure steam if doing so
would have a material adverse effect on the refinerys
operations. The price for such high pressure steam is calculated
using a formula that is based on steam flow and the price of
natural gas as published in Inside F.E.R.C.s Gas
Market Report under the heading Prices of Spot Gas
delivered to Pipelines for Southern Star Central Gas
Pipeline, Inc. for Texas, Oklahoma and Kansas.
The Partnership is also obligated to make available to us any
nitrogen produced by the Linde air separation plant that is not
required for the operation of the nitrogen fertilizer plant, as
determined by the Partnership in a commercially reasonable
manner. The price for the nitrogen is based on a cost of $0.035
cents per kilowatt hour, as adjusted to reflect changes in the
Partnerships electric bill.
The agreement also provides that both we and the Partnership
must deliver instrument air to one another in some
circumstances. The Partnership must make instrument air
available for purchase by us at a minimum flow rate, to the
extent produced by the Linde air separation plant and available
to the Partnership. The price for such instrument air is $18,000
per month, prorated according to the number of days of use per
month, subject to certain adjustments, including adjustments to
reflect changes in the Partnerships electric bill. To the
extent that instrument air is not available from the Linde air
separation plant and is available from us, we are required to
make instrument air available to the Partnership for purchase at
a price of $18,000 per month, prorated according to the number
of days of use per month, subject to certain adjustments,
including adjustments to reflect changes in our electric bill.
With respect to oxygen requirements, the Partnership is
obligated to provide us with oxygen produced by the Linde air
separation plant and made available to the Partnership to the
extent that such oxygen is not required for operation of the
nitrogen fertilizer plant. The oxygen is required to meet
certain specifications and is to be sold at a fixed price.
The agreement also addresses the means by which we and the
Partnership obtain natural gas. Currently, natural gas is
delivered to both the nitrogen fertilizer plant and our refinery
pursuant to a contract between us and Atmos Energy Corp., or
Atmos. Under the feedstock and shared services agreement, the
Partnership reimburses us for natural gas transportation and
natural gas supplies purchased on behalf of the Partnership. At
our request or at the request of the Partnership, in order to
supply the Partnership with natural gas directly, both parties
will be required to use their commercially reasonable efforts to
(i) add the Partnership as a party to the current contract
with Atmos or reach some other mutually acceptable accommodation
with Atmos whereby both we and the Partnership would each be
able to receive, on an individual basis, natural gas
transportation service from Atmos on similar terms and
conditions as set forth in the current contract, and
(ii) purchase natural gas supplies on their own account.
The agreement also addresses the allocation of various other
feedstocks, services and related costs between the parties. Sour
water, water for use in fire emergencies and costs associated
with security services are all allocated between the two parties
by the terms of the agreement. The agreement also requires the
Partnership to reimburse us for utility costs related to a
sulfur processing agreement between Tessenderlo Kerley, Inc. and
us. The Partnership has a similar agreement with Tessenderlo
Kerley. Otherwise, costs relating to both our and the
Partnerships existing agreements with Tessenderlo Kerley
are allocated equally between the two parties except in certain
circumstances.
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The parties may temporarily suspend the provision of feedstocks
or services pursuant to the terms of the agreement if repairs or
maintenance are necessary on applicable facilities.
Additionally, the agreement imposes minimum insurance
requirements on the parties and their affiliates.
The agreement has an initial term of 20 years, which will
be automatically extended for successive five-year renewal
periods. Either party may terminate the agreement, effective
upon the last day of a term, by giving notice no later than
three years prior to a renewal date. The agreement will also be
terminable by mutual consent of the parties or if one party
breaches the agreement and does not cure within applicable cure
periods and the breach materially and adversely affects the
ability of the terminating party to operate its facility.
Additionally, the agreement may be terminated in some
circumstances if substantially all of the operations at the
nitrogen fertilizer plant or the refinery are permanently
terminated, or if either party is subject to a bankruptcy
proceeding, or otherwise becomes insolvent.
Either party is entitled to assign its rights and obligations
under the agreement to an affiliate of the assigning party, to a
partys lenders for collateral security purposes, or to an
entity that acquires all or substantially all of the equity or
assets of the assigning party related to the refinery or
fertilizer plant, as applicable, in each case subject to
applicable consent requirements. The agreement contains an
obligation to indemnify the other party and its affiliates
against liability arising from breach of the agreement,
negligence, or willful misconduct by the indemnifying party or
its affiliates. The indemnification obligation will be reduced,
as applicable, by amounts actually recovered by the indemnified
party from third parties or insurance coverage. The agreement
also contains a provision that prohibits recovery of lost
profits or revenue, or special, incidental, exemplary, punitive
or consequential damages from either party or certain affiliates.
Coke Supply
Agreement
We entered into a coke supply agreement with the Partnership in
October 2007 pursuant to which we supply pet coke to the
Partnership. This agreement provides that we must deliver to the
Partnership during each calendar year an annual required amount
of pet coke equal to the lesser of (i) 100 percent of
the pet coke produced at our petroleum refinery or
(ii) 500,000 tons of pet coke. The Partnership is also
obligated to purchase this annual required amount. If during a
calendar month we produce more than 41,667 tons of pet coke,
then the Partnership has the option to purchase the excess at
the purchase price provided for in the agreement. If the
Partnership declines to exercise this option, we may sell the
excess to a third party.
The price which the Partnership pays for the pet coke is based
on the lesser of a coke price derived from the price received by
the Partnership for UAN (subject to a UAN-based price ceiling
and floor) and a coke index price but in no event will the pet
coke price be less than zero. The Partnership also pays any
taxes associated with the sale, purchase, transportation,
delivery, storage or consumption of the pet coke. The
Partnership is entitled to offset any amount payable for the pet
coke against any amount due from us under the feedstock and
shared services agreement between the parties. If the
Partnership fails to pay an invoice on time, the Partnership
will pay interest on the outstanding amount payable at a rate of
three percent above the prime rate.
In the event we deliver pet coke to the Partnership on a short
term basis and such pet coke is off-specification on more than
20 days in any calendar year, there will be a price
adjustment to compensate the Partnership
and/or
capital contributions will be made to the Partnership to allow
it to modify its equipment to process the pet coke received. If
we determine that there will be a change in pet coke quality on
a long term basis, then we will be required to notify the
Partnership of such change with at least three years
notice. The Partnership will then determine the appropriate
changes necessary to its nitrogen fertilizer plant in order to
process such off-specification coke. We will compensate the
Partnership for the cost of making such modifications
and/or
adjust the price of pet coke on a mutually agreeable
commercially reasonable basis.
The terms of the coke supply agreement provide benefits both to
our petroleum business and the Partnership. In return for
receiving a potentially lower price for coke in periods when the
coke price
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is impacted by lower UAN prices, we enjoy the following benefits
associated with the disposition of a low value by-product of the
refining process: avoiding the capital cost and operating
expenses associated with coke handling; enjoying flexibility in
our crude slate and operations as a result of not being required
to meet a specific coke quality; avoiding the administration,
credit risk and marketing fees associated with selling coke; and
obtaining a contractual right of first refusal to a secure and
reliable long-term source of hydrogen from the Partnership to
back up our refinerys own internal hydrogen production. We
require hydrogen in order to remove sulfur from diesel fuel and
gasoline.
The cost of the pet coke supplied by us to the Partnership in
most cases is lower than the price which the Partnership
otherwise would pay to third parties. The cost to the
Partnership is lower both because the actual price paid is lower
and because the Partnership pays significantly reduced
transportation costs (since the pet coke is supplied by an
adjacent facility which involves no freight or tariff costs). In
addition, because the cost the Partnership pays is formulaically
related to the price received for UAN (subject to a UAN based
price floor and ceiling), the Partnership enjoys lower pet coke
costs during periods of lower revenues regardless of the
prevailing pet coke market.
The Partnership may be obligated to provide security for its
payment obligations under the agreement if in our sole judgment
there is a material adverse change in the Partnerships
financial condition or liquidity position or in the
Partnerships ability to make payments. This security shall
not exceed an amount equal to 21 times the average daily dollar
value of pet coke purchased by the Partnership for the
90-day
period preceding the date on which we give notice to the
Partnership that we have deemed that a material adverse change
has occurred. Unless otherwise agreed by us and the Partnership,
the Partnership can provide such security by means of a standby
or documentary letter of credit, prepayment, a surety
instrument, or a combination of the foregoing. If such security
is not provided by the Partnership, we may require the
Partnership to pay for future deliveries of pet coke on a
cash-on-delivery
basis, failing which we may suspend delivery of pet coke until
such security is provided and terminate the agreement upon
30 days prior written notice. Additionally, the
Partnership may terminate the agreement within 60 days of
providing security, so long as the Partnership provides five
days prior written notice.
The agreement has an initial term of 20 years, which will
be automatically extended for successive five year renewal
periods. Either party may terminate the agreement by giving
notice no later than three years prior to a renewal date. The
agreement is also terminable by mutual consent of the parties or
if a party breaches the agreement and does not cure within
applicable cure periods. Additionally, the agreement may be
terminated in some circumstances if substantially all of the
operations at the nitrogen fertilizer plant or our refinery are
permanently terminated, or if either party is subject to a
bankruptcy proceeding or otherwise becomes insolvent.
Either party may assign its rights and obligations under the
agreement to an affiliate of the assigning party, to a
partys lenders for collateral security purposes, or to an
entity that acquires all or substantially all of the equity or
assets of the assigning party related to the refinery or
fertilizer plant, as applicable, in each case subject to
applicable consent requirements.
The agreement contains an obligation to indemnify the other
party and its affiliates against liability arising from breach
of the agreement, negligence, or willful misconduct by the
indemnifying party or its affiliates. The indemnification
obligation will be reduced, as applicable, by amounts actually
recovered by the indemnified party from third parties or
insurance coverage. The agreement also contains a provision that
prohibits recovery of lost profits or revenue, or special,
incidental, exemplary, punitive or consequential damages from
either party or certain affiliates.
Raw Water and
Facilities Sharing Agreement
We entered into a raw water and facilities sharing agreement
with the Partnership in October 2007 which (i) provides for
the allocation of raw water resources between our refinery and
the nitrogen fertilizer plant and (ii) provides for the
management of the water intake system (consisting primarily of a
water intake structure, water pumps, meters, and a short run of
piping between the intake structure and the origin of the
separate pipes that transport the water to each facility) which
draws raw water
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from the Verdigris River for both our facility and the nitrogen
fertilizer plant. This agreement provides that a water
management team consisting of one representative from each party
to the agreement will manage the Verdigris River water intake
system. The water intake system is owned and operated by us. The
agreement provides that both companies have an undivided
one-half interest in the water rights which will allow the water
to be removed from the Verdigris River for use at our refinery
and the nitrogen fertilizer plant.
The agreement provides that both the nitrogen fertilizer plant
and our refinery are entitled to receive sufficient amounts of
water from the Verdigris River each day to enable them to
conduct their businesses at their appropriate operational
levels. However, if the amount of water available from the
Verdigris River is insufficient to satisfy the operational
requirements of both facilities, then such water shall be
allocated between the two facilities on a prorated basis. This
prorated basis will be determined by calculating the percentage
of water used by each facility over the two calendar years prior
to the shortage, making appropriate adjustments for any
operational outages involving either of the two facilities.
Costs associated with operation of the water intake system and
administration of water rights will be allocated on a prorated
basis, calculated by us based on the percentage of water used by
each facility during the calendar year in which such costs are
incurred. However, in certain circumstances, such as where one
party bears direct responsibility for the modification or repair
of the water pumps, one party will bear all costs associated
with such activity. Additionally, the Partnership must reimburse
us for electricity required to operate the water pumps on a
prorated basis that is calculated monthly.
Either we or the Partnership are entitled to terminate the
agreement by giving at least three years prior written
notice. Between the time that notice is given and the
termination date, we must cooperate with the Partnership to
allow the Partnership to build its own water intake system on
the Verdigris River to be used for supplying water to its
nitrogen fertilizer plant. We will be required to grant
easements and access over our property so that the Partnership
can construct and utilize such new water intake system, provided
that no such easements or access over our property shall have a
material adverse affect on our business or operations at the
refinery. The Partnership will bear all costs and expenses for
such construction if it is the party that terminated the
original water sharing agreement. If we terminate the original
water sharing agreement, the Partnership may either install a
new water intake system at its own expense, or require us to
sell the existing water intake system to the Partnership for a
price equal to the depreciated book value of the water intake
system as of the date of transfer.
Either party may assign its rights and obligations under the
agreement to an affiliate of the assigning party, to a
partys lenders for collateral security purposes, or to an
entity that acquires all or substantially all of the equity or
assets of the assigning party related to the refinery or
fertilizer plant, as applicable, in each case subject to
applicable consent requirements. The parties may obtain
injunctive relief to enforce their rights under the agreement.
The agreement contains an obligation to indemnify the other
party and its affiliates against liability arising from breach
of the agreement, negligence, or willful misconduct by the
indemnifying party or its affiliates. The indemnification
obligation will be reduced, as applicable, by amounts actually
recovered by the indemnified party from third parties or
insurance coverage. The agreement also contains a provision that
prohibits recovery of lost profits or revenue, or special,
incidental, exemplary, punitive or consequential damages from
either party or certain affiliates.
The term of the agreement is perpetual unless (1) the
agreement is terminated by either party upon three years
prior written notice in the manner described above or
(2) the agreement is otherwise terminated by the mutual
written consent of the parties.
Real Estate
Transactions
Land Transfer.
We have transferred
certain parcels of land to the Partnership, including land where
the Partnership expects to expand the nitrogen fertilizer
facility.
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Cross-Easement Agreement.
We entered
into a cross-easement agreement with the Partnership in October
2007 so that both we and the Partnership can access and utilize
each others land in certain circumstances in order to
operate our respective businesses. The agreement grants
easements for the benefit of both parties and establishes
easements for operational facilities, pipelines, equipment,
access, and water rights, among other easements. The intent of
the agreement is to structure easements which provides
flexibility for both parties to develop their respective
properties, without depriving either party of the benefits
associated with the continuous reasonable use of the other
partys property.
The agreement provides that facilities located on each
partys property will generally be owned and maintained by
the property-owning party; provided, however, that in certain
specified cases where a facility that benefits one party is
located on the other partys property, the benefited party
will have the right to use, and will be responsible for
operating and maintaining, the overlapping facility.
The easements granted under the agreement are non-exclusive to
the extent that future grants of easements do not interfere with
easements granted under the agreement. The duration of the
easements granted under the agreement varies, and some are
perpetual. Easements pertaining to certain facilities that are
required to carry out the terms of our other agreements with the
Partnership terminate upon the termination of such related
agreements. We also granted a water rights easement to the
Partnership which is perpetual in duration. See
Raw Water and Facilities Sharing
Agreement.
The agreement contains an obligation to indemnify, defend and
hold harmless the other party against liability arising from
negligence or willful misconduct by the indemnifying party. The
agreement also requires the parties to carry minimum amounts of
employers liability insurance, commercial general
liability insurance, and other types of insurance. If either
party transfers its fee simple ownership interest in the real
property governed by the agreement, the new owner of the real
property will be deemed to have assumed all of the obligations
of the transferring party under the agreement, except that the
transferring party will retain liability for all obligations
under the agreement which arose prior to the date of transfer.
Lease Agreement.
We have entered into a
five-year lease agreement with the Partnership under which we
lease certain office and laboratory space to the Partnership.
This agreement expires in October 2012.
Environmental
Agreement
We entered into an environmental agreement with the Partnership
in October 2007 which provides for certain indemnification and
access rights in connection with environmental matters affecting
our refinery and the nitrogen fertilizer plant. Generally, both
we and the Partnership agreed to indemnify and defend each other
and each others affiliates against liabilities associated
with certain hazardous materials and violations of environmental
laws that are a result of or caused by the indemnifying
partys actions or business operations. This obligation
extends to indemnification for liabilities arising out of
off-site disposal of certain hazardous materials.
Indemnification obligations of the parties will be reduced by
applicable amounts recovered by an indemnified party from third
parties or from insurance coverage.
To the extent that one partys property experiences
environmental contamination due to the activities of the other
party and the contamination is known at the time the agreement
was entered into, the contaminating party is required to
implement all government-mandated environmental activities
relating to the contamination, or else indemnify the
property-owning party for expenses incurred in connection with
implementing such measures.
To the extent that liability arises from environmental
contamination that is caused by us but is also commingled with
environmental contamination caused by the Partnership, we may
elect in our sole discretion and at our own cost and expense to
perform government-mandated environmental activities relating to
such liability, subject to certain conditions and provided that
we will not waive any rights to indemnification or compensation
otherwise provided for in the agreement.
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The agreement also addresses situations in which a partys
responsibility to implement such government-mandated
environmental activities as described above may be hindered by
the property-owning partys creation of capital
improvements on the property. If a contaminating party bears
such responsibility but the property-owning party desires to
implement a planned and approved capital improvement project on
its property, the parties must meet and attempt to develop a
soil management plan together. If the parties are unable to
agree on a soil management plan 30 days after receiving
notice, the property-owning party may proceed with its own
commercially reasonable soil management plan. The contaminating
party is responsible for the costs of disposing of hazardous
materials pursuant to such plan.
If the property-owning party needs to do work that is not a
planned and approved capital improvement project but is
necessary to protect the environment, health, or the integrity
of the property, other procedures will be implemented. If the
contaminating party still bears responsibility to implement
government-mandated environmental activities relating to the
property and the property-owning party discovers contamination
caused by the other party during work on the capital improvement
project, the property-owning party will give the contaminating
party prompt notice after discovery of the contamination, and
will allow the contaminating party to inspect the property. If
the contaminating party accepts responsibility for the
contamination, it may proceed with government-mandated
environmental activities relating to the contamination, and it
will be responsible for the costs of disposing of hazardous
materials relating to the contamination. If the contaminating
party does not accept responsibility for such contamination or
fails to diligently proceed with government-mandated
environmental activities related to the contamination, then the
contaminating party must indemnify and reimburse the
property-owning party upon the property-owning partys
demand for costs and expenses incurred by the property-owning
party in proceeding with such government-mandated environmental
activities.
The agreement also provides for indemnification in the case of
contamination or releases of hazardous materials that are
present but unknown at the time the agreement is entered into to
the extent such contamination or releases are identified in
reasonable detail during the period ending five years after the
date of the agreement. The agreement further provides for
indemnification in the case of contamination or releases which
occur subsequent to the date the agreement is entered into. If
one party causes such contamination or release on the other
partys property, the latter party must notify the
contaminating party, and the contaminating party must take steps
to implement all government-mandated environmental activities
relating to the contamination, or else indemnify the
property-owning party for the costs associated with doing such
work.
The agreement also grants each party reasonable access to the
other partys property for the purpose of carrying out
obligations under the agreement. However, both parties must keep
certain information relating to the environmental conditions on
the properties confidential. Furthermore, both parties are
prohibited from investigating soil or groundwater conditions
except as required for government-mandated environmental
activities, in responding to an accidental or sudden
contamination of certain hazardous materials, or in connection
with implementation of a comprehensive coke management plan as
discussed below.
In accordance with the agreement, the parties developed a
comprehensive coke management plan after the execution of the
environmental agreement. The plan established procedures for the
management of pet coke and the identification of significant pet
coke-related contamination. Also, the parties agreed to
indemnify and defend one another and each others
affiliates against liabilities arising under the coke management
plan or relating to a failure to comply with or implement the
coke management plan.
Either party will be entitled to assign its rights and
obligations under the agreement to an affiliate of the assigning
party, to a partys lenders for collateral security
purposes, or to an entity that acquires all or substantially all
of the equity or assets of the assigning party related to the
refinery or fertilizer plant, as applicable, in each case
subject to applicable consent requirements. The term of the
agreement is for at least 20 years, or for so long as the
feedstock and shared services agreement is in force, whichever
is longer. The agreement also contains a provision that
prohibits recovery of lost
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profits or revenue, or special, incidental, exemplary, punitive
or consequential damages from either party or certain of its
affiliates.
We have entered into a supplement to the environmental agreement
confirming that we remain responsible for existing environmental
conditions on land that we transferred to the Partnership.
Omnibus
Agreement
We entered into an omnibus agreement with the managing general
partner and the Partnership in October 2007. The following
discussion describes the material terms of the omnibus agreement.
Under the omnibus agreement the Partnership has agreed not to,
and will cause its controlled affiliates not to, engage in,
whether by acquisition or otherwise, (i) the ownership or
operation within the United States of any refinery with
processing capacity greater than 20,000 barrels per day
whose primary business is producing transportation fuels or
(ii) the ownership or operation outside the United States
of any refinery, regardless of its processing capacity or
primary business, or a refinery restricted business, in either
case, for so long as we continue to own at least 50% of the
Partnerships outstanding units. The restrictions will not
apply to:
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any refinery restricted business acquired as part of a business
or package of assets if a majority of the value of the total
assets or business acquired is not attributable to a refinery
restricted business, as determined in good faith by the managing
general partners board of directors; however, if at any
time the Partnership completes such an acquisition, the
Partnership must, within 365 days of the closing of the
transaction, offer to sell the refinery-related assets to us for
their fair market value plus any additional tax or other similar
costs that would be required to transfer the refinery-related
assets to us separately from the acquired business or package of
assets;
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engaging in any refinery restricted business subject to the
offer to us described in the immediately preceding bullet point
pending our determination whether to accept such offer and
pending the closing of any offers we accept;
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engaging in any refinery restricted business if we have
previously advised the Partnership that our board of directors
has elected not to cause us to acquire or seek to acquire such
business; or
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acquiring up to 9.9% of any class of securities of any publicly
traded company that engages in any refinery restricted business.
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Under the omnibus agreement, we have agreed not to, and will
cause our controlled affiliates other than the Partnership not
to, engage in, whether by acquisition or otherwise, the
production, transportation or distribution, on a wholesale
basis, of fertilizer in the contiguous United States, or a
fertilizer restricted business, for so long as we and certain of
our affiliates continue to own at least 50% of the
Partnerships outstanding units. The restrictions do not
apply to:
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any fertilizer restricted business acquired as part of a
business or package of assets if a majority of the value of the
total assets or business acquired is not attributable to a
fertilizer restricted business, as determined in good faith by
our board of directors, as applicable; however, if at any time
we complete such an acquisition, we must, within 365 days
of the closing of the transaction, offer to sell the
fertilizer-related assets to the Partnership for their fair
market value plus any additional tax or other similar costs that
would be required to transfer the fertilizer-related assets to
the Partnership separately from the acquired business or package
of assets;
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engaging in any fertilizer restricted business subject to the
offer to the Partnership described in the immediately preceding
bullet point pending the Partnerships determination
whether to accept such offer and pending the closing of any
offers the Partnership accepts;
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engaging in any fertilizer restricted business if the
Partnership has previously advised us that it has elected not to
acquire such business; or
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acquiring up to 9.9% of any class of securities of any publicly
traded company that engages in any fertilizer restricted
business.
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Under the omnibus agreement we have also agreed that the
Partnership has a preferential right to acquire any assets or
group of assets that do not constitute (i) assets used in a
refinery restricted business or (ii) assets used in a
fertilizer restricted business. In determining whether to cause
the Partnership to exercise any preferential right under the
omnibus agreement, the managing general partner will be
permitted to act in its sole discretion, without any fiduciary
obligation to the Partnership or the unitholders whatsoever
(including us). These obligations will continue until such time
as we and certain of our affiliates cease to own at least 50% of
the Partnerships outstanding units.
Services
Agreement
We entered into a services agreement with the Partnership and
the managing general partner of the Partnership in October 2007
pursuant to which we provide certain management and other
services to the Partnership and the managing general partner of
the Partnership. Under this agreement, the managing general
partner of the Partnership engaged us to conduct the day-to-day
business operations of the Partnership. We provide the
Partnership with the following services under the agreement,
among others:
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services by our employees as the Partnerships corporate
executive officers, including chief executive officer, chief
operating officer, chief financial officer, general counsel,
fertilizer general manager, and vice president for
environmental, health and safety, except that those who serve in
such capacities under the agreement serve the Partnership on a
shared, part-time basis only, unless we and the Partnership
agree otherwise;
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administrative and professional services, including legal,
accounting services, human resources, insurance, tax, credit,
finance, government affairs and regulatory affairs;
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management of the property of the Partnership and Coffeyville
Resources Nitrogen Fertilizers, LLC, a subsidiary of the
Partnership, in the ordinary course of business;
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recommendations on capital raising activities, including the
issuance of debt or equity securities, the entry into credit
facilities and other capital market transactions;
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managing or overseeing litigation and administrative or
regulatory proceedings, and establishing appropriate insurance
policies for the Partnership, and providing safety and
environmental advice;
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recommending the payment of distributions; and
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managing or providing advice for other projects as may be agreed
by us and the managing general partner of the Partnership from
time to time.
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As payment for services provided under the agreement, the
Partnership, the managing general partner of the Partnership, or
Coffeyville Resources Nitrogen Fertilizers, LLC, the
Partnerships operating subsidiary, must pay us
(i) all costs incurred by us in connection with the
employment of our employees, other than administrative
personnel, who provide services to the Partnership under the
agreement on a full-time basis, but excluding share-based
compensation; (ii) a prorated share of costs incurred by us
in connection with the employment of our employees, other than
administrative personnel, who provide services to the
Partnership under the agreement on a part-time basis, but
excluding share-based compensation, and such prorated share
shall be determined by us on a commercially reasonable basis,
based on the percent of total working time that such shared
personnel are engaged in performing services for the
Partnership; (iii) a prorated share of certain
administrative costs, including payroll, office costs, services
by outside vendors, other sales, general and administrative
costs and depreciation and amortization; and (iv) various
other administrative costs in accordance with the terms of the
agreement, including travel, insurance, legal and audit
services, government and public relations and bank charges. The
Partnership must pay us within 15 days for invoices we
submit under the agreement.
The Partnership and its managing general partner are not
required to pay any compensation, salaries, bonuses or benefits
to any of our employees who provide services to the Partnership
or its
257
managing general partner on a full-time or part-time basis; we
will continue to pay their compensation. However, personnel
performing the actual day-to-day business and operations at the
nitrogen fertilizer plant level will be employed directly by the
Partnership and its subsidiaries, and the Partnership will bear
all personnel costs for these employees.
Either we or the managing general partner of the Partnership may
temporarily or permanently exclude any particular service from
the scope of the agreement upon 90 days notice. We also
have the right to delegate the performance of some or all of the
services to be provided pursuant to the agreement to one of our
affiliates or any other person or entity, though such delegation
does not relieve us from our obligations under the agreement.
Either we or the managing general partner of the Partnership may
terminate the agreement upon at least 90 days notice,
but not more than one years notice. Furthermore, the
managing general partner of the Partnership may terminate the
agreement immediately if we become bankrupt, or dissolve and
commence liquidation or
winding-up.
In order to facilitate the carrying out of services under the
agreement, we and our affiliates, on the one hand, and the
Partnership, on the other, have granted one another certain
royalty-free, non-exclusive and non-transferable rights to use
one anothers intellectual property under certain
circumstances.
The agreement also contains an indemnity provision whereby the
Partnership, its managing general partner, and Coffeyville
Resources Nitrogen Fertilizers, LLC, as indemnifying parties,
agree to indemnify us and our affiliates (other than the
indemnifying parties themselves) against losses and liabilities
incurred in connection with the performance of services under
the agreement or any breach of the agreement, unless such losses
or liabilities arise from a breach of the agreement by us or
other misconduct on our part, as provided in the agreement. The
agreement also contains a provision stating that we are an
independent contractor under the agreement and nothing in the
agreement may be construed to impose an implied or express
fiduciary duty owed by us, on the one hand, to the recipients of
services under the agreement, on the other hand. The agreement
prohibits recovery of lost profits or revenue, or special,
incidental, exemplary, punitive or consequential damages from us
or certain affiliates, except in cases of gross negligence,
willful misconduct, bad faith, reckless disregard in performance
of services under the agreement, or fraudulent or dishonest acts
on our part.
For the year ended December 31, 2007, the total amount paid
or payable to us pursuant to the services agreement was
$1.8 million.
Registration
Rights Agreement
We entered into a registration rights agreement with the
Partnership in October 2007 pursuant to which the Partnership
may be required to register the sale of our units (as well as
any common units issuable upon conversion of units held by us).
Under the registration rights agreement, following any initial
offering, we will have the right to request that the Partnership
register the sale of units held by us (and the common units
issuable upon conversion of units held by us) on our behalf on
three occasions including requiring the Partnership to make
available shelf registration statements permitting sales of
common units into the market from time to time over an extended
period. In addition, we have the ability to exercise certain
piggyback registration rights with respect to our own securities
if the Partnership elects to register any of its equity
interests. The registration rights agreement also includes
provisions dealing with holdback agreements, indemnification and
contribution, and allocation of expenses. All of the
Partnerships units held by us will be entitled to these
registration rights.
258
DESCRIPTION OF
OUR INDEBTEDNESS AND THE CASH FLOW SWAP
Second Amended
and Restated Credit and Guaranty Agreement
On December 28, 2006, Coffeyville Resources, LLC, as the
borrower, and Coffeyville Refining & Marketing, Inc.,
Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude
Transportation, Inc., Coffeyville Pipeline, Inc., Coffeyville
Terminal, Inc., CL JV Holdings, LLC, which we refer to
collectively as Holdings, and certain of their subsidiaries as
guarantors entered into a Second Amended and Restated Credit and
Guaranty Agreement with Goldman Sachs Credit Partners L.P. and
Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and
Joint Bookrunners, Credit Suisse, as Administrative Agent,
Collateral Agent, Funded LC Issuing Bank and Revolving Issuing
Bank, Deutsche Bank Trust Company Americas, as Syndication
Agent, and ABN Amro Bank N.V., as Documentation Agent.
If the managing general partner of the Partnership elects to
pursue a public or private offering of limited partner interests
in the Partnership, we expect that any such transaction would
require amendments to our Credit Facility, as well as to the
Cash Flow Swap, in order to remove the Partnership and its
subsidiaries as obligors under such instruments. Any such
amendments could result in changes to the Credit Facilitys
pricing, mandatory prepayment provisions, covenants and other
terms and could result in increased interest costs and require
payment by us of additional fees. We have agreed to use our
commercially reasonable efforts to obtain such amendments if the
managing general partner elects to cause the Partnership to
pursue a public or private offering and gives us at least
90 days written notice. However, we cannot assure you that
we will be able to obtain any such amendment on terms acceptable
to us or at all. If we are not able to amend the Credit Facility
on terms satisfactory to us, we may need to refinance it with
other facilities. We will not be considered to have used our
commercially reasonable efforts to obtain such
amendments if we do not effect the requested modifications due
to (i) payment of fees to the lenders or the swap
counterparty, (ii) the costs of this type of amendment,
(iii) an increase in applicable margins or spreads or
(iv) changes to the terms required by the lenders including
covenants, events of default and repayment and prepayment
provisions provided that (i), (ii), (iii) and (iv) in
the aggregate are not likely to have a material adverse effect
on us. In order to effect the requested amendments, we may
require that (1) the Partnerships initial public or
private offering generate at least $140 million in net
proceeds to us and (2) the Partnership raise an amount of
cash (from the issuance of equity or incurrence of indebtedness)
equal to $75.0 million minus the amount of capital
expenditures for which it will reimburse us from the proceeds of
its initial public or private offering and distribute that cash
to us prior to, or concurrently with, the closing of its initial
public or private offering.
The following summary of the material terms of the Credit
Facility is only a general description and is not complete and,
as such, is subject to and is qualified in its entirety by
reference to the provisions of the Credit Facility.
The Credit Facility provides financing of up to
$1.075 billion, consisting of $775.0 million of
tranche D term loans, a $150.0 million revolving
credit facility, and a funded letter of credit facility of
$150.0 million issued in support of the Cash Flow Swap.
The revolving loan facility of $150.0 million provides for
direct cash borrowings for general corporate purposes on a
short-term basis. Letters of credit issued under the revolving
loan facility are subject to a $75.0 million sub-limit. The
revolving loan commitment expires on December 28, 2012. We
have an option to extend this maturity upon written notice to
our lenders; however, the revolving loan maturity cannot be
extended beyond the final maturity of the term loans, which is
December 28, 2013.
The $150.0 million funded letter of credit facility
provides credit support for our obligations under the Cash Flow
Swap. The funded letter of credit facility is fully cash
collateralized by the funding by the lenders of cash into the
credit linked deposit account. This account is held by the
funded letter of credit issuing bank. Contingent upon the
requirements of the Cash Flow Swap, we have the ability to
reduce the funded letter of credit at any time upon written
notice to the lenders. The funded letter of credit facility
expires on December 28, 2010.
259
Coffeyville Resources, LLC initially entered into a first lien
credit facility and a second lien credit facility on
June 24, 2005 in connection with the acquisition of all of
the subsidiaries of Coffeyville Group Holdings, LLC by the
Goldman Sachs Funds and the Kelso Funds. The first lien credit
facility consisted of $225.0 million of term loans,
$50.0 million of delayed draw term loans, a
$100.0 million revolving loan facility and a funded letter
of credit facility of $150.0 million, and the second lien
credit facility included a $275.0 million term loan. The
first lien credit facility was subsequently amended and restated
on June 29, 2006 on substantially the same terms as the
original agreement, as amended. The primary reason for the June
2006 amendment and restatement was to reduce the applicable
margin spreads for borrowings on the first lien term loans and
the funded letter of credit facility and to make the capital
expenditure covenant less restrictive. On December 28,
2006, Coffeyville Resources, LLC repaid all indebtedness then
outstanding under the first lien credit facility and second lien
credit facility and entered into the Credit Facility.
Interest Rate and Fees.
The
tranche D term loans bear interest at either (a) the
greater of the prime rate and the federal funds effective rate
plus 0.5%, plus in either case 2.25% or, at the borrowers
option, (b) LIBOR plus 3.25% (with step-downs to the prime
rate/federal funds effective rate plus 1.75% or 1.50% or LIBOR
plus 2.75% or 2.50%, respectively, upon achievement of certain
rating conditions). The revolving loan facility borrowings bear
interest at either (a) the greater of the prime rate and
the Federal funds effective rate plus 0.5%, plus in either case
2.25% or, at the borrowers option, (b) LIBOR plus
3.25% (with step-downs to the prime rate/federal funds effective
rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%,
respectively, upon achievement of certain rating conditions).
Letters of credit issued under the $75.0 million sub-limit
available under the revolving loan facility are subject to a fee
equal to the applicable margin on revolving LIBOR loans owing to
all revolving lenders and a fronting fee of 0.25% per annum
owing to the issuing lender. Funded letters of credit are
subject to a fee equal to the applicable margin on term LIBOR
loans owing to all funded letter of credit lenders and a
fronting fee of 0.125% per annum owing to the issuing lender.
The borrower is also obligated to pay a fee of 0.10% to the
administrative agent on a quarterly basis based on the average
balance of funded letters of credit outstanding during the
calculation period, for the maintenance of a credit linked
deposit account backstopping funded letters of credit. In
addition to the fees stated above, the Credit Facility requires
the borrower to pay 0.50% in commitment fees on the unused
portion of the revolving loan facility. The interest rate on the
term loans under the Credit Facility on December 31, 2006
and December 31, 2007 was 8.36% and 7.98%, respectively.
Prepayments.
The Credit Facility
requires the borrower to prepay outstanding loans, subject to
certain exceptions, with:
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100% of the net asset sale proceeds received by Holdings or any
of its subsidiaries from specified asset sales and net
insurance/condemnation proceeds, if the borrower does not
reinvest those proceeds in assets to be used in its business or
to make other certain permitted investments within
12 months or if, within 12 months of receipt, the
borrower does not contract to reinvest those proceeds in assets
to be used in its business or to make other certain permitted
investments within 18 months of receipt, each subject to
certain limitations;
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100% of the cash proceeds from the incurrence of specified debt
obligations by Holdings or any of its subsidiaries; and
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75% of consolidated excess cash flow less 100% of
voluntary prepayments made during the fiscal year; provided that
this percentage will be reduced to 50% if the total leverage
ratio at the end of such fiscal year is less than 1.50:1.00 and
25% if the total leverage ratio as of the end of such fiscal
year is less than 1.00:1.00;
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Mandatory prepayments will be applied first to the term loan,
second to the swing line loans, third to the revolving loans,
fourth to outstanding reimbursement obligations with respect to
revolving letters of credit and funded letters of credit, and
fifth to cash collateralize revolving letters of credit and
funded letters of credit.
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Voluntary prepayments of loans under the Credit Facility are
permitted, in whole or in part, at the borrowers option,
without premium or penalty.
Amortization.
The tranche D term
loans are repayable in quarterly installments in a principal
amount equal to the principal amount of the tranche D term
loans outstanding on the quarterly installment date multiplied
by 0.25% for each quarterly installment made prior to
April 1, 2013 and 23.5% for each quarterly installment made
during the period commencing on April 1, 2013 through
maturity on December 28, 2013.
Collateral and Guarantors.
All
obligations under the Credit Facility are guaranteed by
Coffeyville Refining & Marketing, Inc., Coffeyville
Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation,
Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC and their
domestic subsidiaries, including the Partnership and CVR Special
GP, LLC. Indebtedness under the Credit Facility is secured by a
first priority security interest in substantially all of
Coffeyville Resources, LLCs assets, including a pledge of
all of the capital stock of its domestic subsidiaries and 65% of
all the capital stock of each of its foreign subsidiaries on a
first lien priority basis.
Certain Covenants and Events of
Default.
The Credit Facility contains
customary covenants. These agreements, among other things,
restrict, subject to certain exceptions, the ability of
Coffeyville Resources, LLC and its subsidiaries to incur
additional indebtedness, create liens on assets, make restricted
junior payments, enter into agreements that restrict subsidiary
distributions, make investments, loans or advances, engage in
mergers, acquisitions or sales of assets, dispose of subsidiary
interests, enter into sale and leaseback transactions, engage in
certain transactions with affiliates and stockholders, change
the business conducted by the credit parties, and enter into
hedging agreements. The Credit Facility provides that
Coffeyville Resources, LLC may not enter into commodity
agreements if, after giving effect thereto, the exposure under
all such commodity agreements exceeds 75% of Actual Production
(the borrowers estimated future production of refined
products based on the actual production for the three prior
months) or for a term of longer than six years from
December 28, 2006. In addition, the borrower may not enter
into material amendments related to any material rights under
the Cash Flow Swap, the Partnerships partnership agreement
or the management agreements with Goldman, Sachs & Co.
and Kelso & Company, L.P. without the prior written
approval of the lenders.
The Credit Facility requires the borrower to maintain a minimum
interest coverage ratio and a maximum total leverage ratio.
These financial covenants are set forth in the table below:
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Minimum Interest
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Maximum
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Fiscal Quarter Ending
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Coverage Ratio
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Leverage Ratio
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June 30, 2008
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3.25:1.00
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3.00:1.00
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September 30, 2008
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3.25:1.00
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2.75:1.00
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December 31, 2008
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3.25:1.00
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2.50:1.00
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March 31, 2009 and thereafter
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3.75:1.00
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2.25:1.00 to
December 31, 2009,
2.00:1.00 thereafter
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In addition, the Credit Facility also requires the borrower to
maintain a maximum capital expenditures limitation of
$125.0 million in 2008, $125.0 million in 2009,
$80.0 million in 2010, and $50.0 million in 2011 and
thereafter. If the actual amount of capital expenditures made in
any fiscal year is less than the amount permitted to be made in
such fiscal year, the amount of such difference may be carried
forward and used to make capital expenditures in succeeding
fiscal years. The capital expenditures limitation will not apply
to any fiscal year commencing with fiscal 2009 if the borrower
obtains a total leverage ratio of less than or equal to
1.25:1.00 for any quarter commencing with the quarter ending
December 31, 2008. We believe that the limitations on our
capital expenditures imposed by the Credit Facility should allow
us to meet our current capital expenditure needs. However if
future events require us or make it beneficial for us to make
capital expenditures beyond those currently planned we would
need to obtain consent from the lenders under our Credit
Facility.
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The Credit Facility also contains customary events of default.
The events of default include the failure to pay interest and
principal when due, including fees and any other amounts owed
under the Credit Facility, a breach of certain covenants under
the Credit Facility, a breach of any representation or warranty
contained in the Credit Facility, any default under any of the
documents entered into in connection with the Credit Facility,
the failure to pay principal or interest or any other amount
payable under other debt arrangements in an aggregate amount of
at least $20 million, a breach or default with respect to
material terms under other debt arrangements in an aggregate
amount of at least $20 million which results in the debt
becoming payable or declared due and payable before its stated
maturity, a breach or default under the Cash Flow Swap that
would permit the holder or holders to terminate the Cash Flow
Swap, events of bankruptcy, judgments and attachments exceeding
$20 million, events relating to employee benefit plans
resulting in liability in excess of $20 million, the
guarantees, collateral documents or the Credit Facility failing
to be in full force and effect or being declared null and void,
any guarantor repudiating its obligations, the failure of the
collateral agent under the Credit Facility to have a lien on any
material portion of the collateral, and any party under the
Credit Facility (other than the agent or lenders under the
Credit Facility) contesting the validity or enforceability of
the Credit Facility.
The Credit Facility also contains an event of default upon the
occurrence of a change of control. Under the Credit Facility, a
change of control means (1) the Goldman Sachs
Funds and the Kelso Funds cease to beneficially own and control,
directly or indirectly, on a fully diluted basis at least 35% of
the economic and voting interests in the capital stock of Parent
(Coffeyville Acquisition LLC or CVR Energy), (2) any person
or group other than the Goldman Sachs Funds
and/or
the
Kelso Funds (a) acquires beneficial ownership of 35% or
more on a fully diluted basis of the voting
and/or
economic interest in the capital stock of Parent and the
percentage voting
and/or
economic interest acquired exceeds the percentage owned by the
Goldman Sachs Funds and the Kelso Funds or (b) shall have
obtained the power to elect a majority of the board of Parent,
(3) Parent shall cease to own and control, directly or
indirectly, 100% on a fully diluted basis of the capital stock
of the borrower, (4) Holdings ceases to beneficially own
and control all of the capital stock of the borrower or
(5) the majority of the seats on the board of Parent cease
to be occupied by continuing directors approved by the
then-existing directors.
Other.
The Credit Facility is subject
to an intercreditor agreement among the lenders and the provider
of the Cash Flow Swap, which relates to, among other things,
priority of liens, payments and proceeds of sale of collateral.
August 2007
Credit Facilities
In August 2007, our subsidiaries entered into three new credit
facilities.
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$25.0 Million Secured
Facility.
Coffeyville Resources, LLC entered
into a new $25.0 million senior secured term loan (the
$25.0 million secured facility). The facility
was secured by the same collateral that secures our existing
Credit Facility. Interest was payable in cash, at our option, at
the base rate plus 1.00% or at the reserve adjusted eurodollar
rate plus 2.00%.
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$25.0 Million Unsecured
Facility.
Coffeyville Resources, LLC entered
into a new $25.0 million senior unsecured term loan (the
$25.0 million unsecured facility). Interest was
payable in cash, at our option, at the base rate plus 1.00% or
at the reserve adjusted eurodollar rate plus 2.00%.
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$75.0 Million Unsecured
Facility.
Coffeyville Refining &
Marketing Holdings, Inc. entered into a new $75.0 million
senior unsecured term loan (the $75.0 million
unsecured facility). Drawings could be made from time to
time in amounts of at least $5.0 million. Interest accrued,
at our option, at the base rate plus 1.50% or at the reserve
adjusted eurodollar rate plus 2.50%. Interest was paid by adding
such interest to the principal amount of loans outstanding. In
addition, a commitment fee equal to 1.00% accrued by adding such
fees to the principal amount of loans outstanding. No amounts
were drawn under this facility.
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All indebtedness outstanding under the $25.0 million
secured facility and the $25.0 million unsecured facility
was repaid in October 2007 with the proceeds of our initial
public offering, and all three facilities were terminated at
that time.
Proposed
Senior Secured Credit Facility
Concurrently with the closing of this offering, we anticipate
that Coffeyville Resources, LLC will enter into a new
$25.0 million senior secured term loan (the proposed
senior secured credit facility). We anticipate that the
proposed senior secured credit facility will be secured by the
same collateral that secures our existing Credit Facility and
will contain covenants substantially similar to the Credit
Facility. Although we have begun negotiations on the new credit
facility, we have not entered into any agreement regarding the
proposed senior secured credit facility, and as such, there is
no guarantee that we will be enter into a credit facility on the
terms described above or at all.
Cash Flow
Swap
In connection with the Subsequent Acquisition and as required
under our then-existing credit facilities, Coffeyville
Acquisition LLC entered into a crack spread hedging transaction
with J. Aron. The agreements underlying the transaction
were subsequently assigned from Coffeyville Acquisition LLC to
Coffeyville Resources, LLC on June 24, 2005. See
Certain Relationships and Related Party
Transactions. The derivative transaction was entered into
for the purpose of managing our exposure to the price
fluctuations in crude oil, heating oil and gasoline markets.
The fixed prices for each product in each calendar quarter are
specified in the applicable swap confirmation. The floating
price for
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crude oil for each quarter equals the average of the closing
settlement price(s) on NYMEX for the Nearby Light Crude Futures
Contract that is first nearby as of any
determination date during that calendar quarter quoted in
U.S. dollars per barrel;
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unleaded gasoline for each quarter equals the average of the
closing settlement prices on NYMEX for the Unleaded Gasoline
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
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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.
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The hedge transaction is governed by the standard form 1992
International Swap and Derivatives Association, Inc., or ISDA
Master Agreement, which includes a schedule to the ISDA Master
Agreement setting forth certain specific transaction terms.
Coffeyville Resources, LLCs obligations under the hedge
transaction are:
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guaranteed by Coffeyville Refining & Marketing, Inc.,
Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude
Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings,
LLC and their domestic subsidiaries;
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secured by a $150.0 million funded letter of credit issued
under the Credit Facility in favor of J. Aron; and
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to the extent J. Arons exposure under the derivative
transaction exceeds $150.0 million, secured by the same
collateral that secures our Credit Facility.
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In addition, J. Aron is an additional named insured and
loss payee under certain insurance policies of Coffeyville
Resources, LLC.
The obligations of J. Aron under the derivative transaction
are guaranteed by The Goldman Sachs Group, Inc.
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The derivative transactions terminate on June 30, 2010.
Prior to the termination date, neither party has a right to
terminate the derivative transaction unless one of the events of
default or termination events under the ISDA Master Agreement
has occurred. In addition to standard events of default and
termination events described in the ISDA Master Agreement, the
schedule to the ISDA Master Agreement provides for the
termination of the derivative transaction if:
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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;
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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
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Coffeyville Resources, LLC fails to maintain a
$150.0 million funded letter of credit in favor of
J. Aron.
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If a termination event occurs, the derivative transaction will
be cash-settled on the termination date designated by a party
entitled to such designation under the ISDA Master Agreement (to
the extent of the amounts owed to either party on the
termination date, without netting of payments) and no further
payments or deliveries under the derivative transaction will be
required.
Intercreditor matters among J. Aron and the lenders under
the Credit Facility are governed by the Intercreditor Agreement.
J. Arons security interest in the collateral is pari
passu with the security interest in the collateral granted under
the Credit Facility. In addition, pursuant to the Intercreditor
Agreement, J. Aron is entitled to vote together as a class
with the lenders under the Credit Facility with respect to
(1) any remedies proposed to be taken by the holders of the
secured obligations with respect to the collateral, (2) any
matters related to a breach, waiver or modification of the
covenants in the Credit Facility that restrict the granting of
liens, the incurrence of indebtedness, and the ability of
Coffeyville Resources, LLC to enter into derivative transactions
for more than 75% of Coffeyville Resources, LLCs actual
production (based on the three-month period preceding the trade
date of the relevant derivative) of refined products or for a
term longer than six years, (3) the maintenance of
insurance, and (4) any matters relating to the collateral.
For any of the foregoing matters, J. Aron is entitled to
vote with the lenders under the Credit Facility as a single
class to the extent of the greater of (x) its exposure
under the derivative transaction, less the amount secured by the
letter of credit and (y) $75 million.
Payment Deferrals
Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our
Companys operations on June 30, 2007, Coffeyville
Resources, LLC entered into several deferral agreements with
J. Aron with respect to the Cash Flow Swap. These deferral
agreements deferred to January 31, 2008 payment of
approximately $123.7 million plus accrued interest
($5.8 million as of June 1, 2008) which we owed to
J. Aron. J. Aron agreed to further defer these
payments to August 31, 2008 but required that we use 37.5%
of our consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferred amounts, but as of
March 31, 2008 we were not required to prepay any portion
of the deferred amount.
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On June 26, 2007, Coffeyville Resources, LLC and
J. Aron & Company entered into a letter agreement
in which J. Aron deferred to August 7, 2007 a
$45.0 million payment which we owed to J. Aron under
the Cash Flow Swap for the period ending June 30, 2007. We
agreed to pay interest on the deferred amount at the rate of
LIBOR plus 3.25%.
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On July 11, 2007, Coffeyville Resources, LLC and
J. Aron entered into a letter agreement in which
J. Aron deferred to July 25, 2007 a separate
$43.7 million payment which we owed to J. Aron under
the Cash Flow Swap for the period ending June 30, 2007.
J. Aron deferred the $43.7 million payment on the
conditions that (a) each of GS Capital Partners V Fund,
L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payment and
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(b) interest accrued on the $43.7 million from
July 9, 2007 to the date of payment at the rate of LIBOR
plus 1.50%.
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On July 26, 2007, Coffeyville Resources, LLC and
J. Aron entered into a letter agreement in which
J. Aron deferred to September 7, 2007 both the
$45.0 million payment due August 7, 2007 (and accrued
interest) and the $43.7 million payment due July 25,
2007 (and accrued interest). J. Aron deferred these
payments on the conditions that (a) each of GS Capital
Partners V Fund, L.P. and Kelso Investment Associates VII, L.P.
agreed to guarantee one half of the payments and
(b) interest accrued on the amounts from July 26, 2007
to the date of payment at the rate of LIBOR plus 1.50%.
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On August 23, 2007, Coffeyville Resources, LLC and
J. Aron entered into a letter agreement in which
J. Aron deferred to January 31, 2008 the
$45.0 million payment due September 7, 2007 (and
accrued interest), the $43.7 million payment due
September 7, 2007 (and accrued interest) and the
$35.0 million payment which we owed to J. Aron under
the Cash Flow Swap to settle hedged volume through
August 15, 2007. J. Aron deferred these payments
(totaling $123.7 million plus accrued interest) on the
conditions that (a) each of GS Capital Partners V Fund,
L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payments and (b) interest accrued
on the amounts to the date of payment at the rate of LIBOR plus
1.50%.
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DESCRIPTION OF
CONCURRENT OFFERING OF CONVERTIBLE NOTES
Concurrently with this offering, we are offering $125,000,000
aggregate principal amount
of % Convertible Senior Notes
due 2013 (the convertible senior notes). We have
also granted the underwriters of the convertible senior note
offering an option to purchase an additional $18.75 million
aggregate principal amount of convertible senior notes solely to
cover over-allotments. The consummation of the convertible
senior notes offering is not conditioned upon the concurrent
consummation of this offering.
We will pay interest on the convertible senior notes in cash
semiannually, in arrears,
on
and
of each year, beginning
on ,
2008. The convertible senior notes will mature
on ,
2013.
The convertible senior notes will be our general unsecured
obligations (except to the extent of the interest escrow
described below) and will rank equal in right of payment to all
of our other senior unsecured indebtedness and senior in right
of payment to all indebtedness that is contractually
subordinated to the convertible senior notes. The convertible
senior notes will be structurally subordinated to (i) all
existing and future claims of our subsidiaries creditors,
including trade creditors and (ii) any preferred stock
which our subsidiaries may issue to the extent of its
liquidation preference. The convertible senior notes will be
effectively subordinated to any of our existing and future
secured indebtedness to the extent of the value of the
collateral securing such indebtedness.
A portion of the proceeds of the concurrent convertible senior
notes offering will be invested in government securities to be
deposited in an escrow account and will be used to make the
first six scheduled interest payments on the convertible senior
notes. These payments will be secured by a pledge of the funds
in the escrow account.
Holders may convert their convertible senior notes at their
option at any time, in whole or in part, prior to the close of
business on the scheduled trading day (as defined in the
prospectus for the convertible senior notes offering)
immediately
preceding ,
2013, only under the following circumstances: (1) during
the five business day period after any five consecutive trading
day period (the measurement period) during which the
trading price (as defined in the prospectus for the convertible
senior notes offering) per $1,000 in principal amount of the
convertible senior notes for each day of the measurement period
was less than 98% of the product of the last reported sale price
(as defined in the prospectus for the convertible senior notes
offering) of our common stock and the applicable conversion rate
for the convertible senior notes for such date; (2) during
any calendar quarter (and only during such calendar quarter)
after the calendar quarter ending September 30, 2008, if
the last reported sale price of our common stock for 20 or more
trading days (as defined in the prospectus for the convertible
senior notes offering) in a period of 30 consecutive trading
days ending on the last trading day of the immediately preceding
calendar quarter exceeds 130% of the applicable conversion price
in effect for the convertible senior notes on the last trading
day of the immediately preceding calendar quarter; or
(3) upon the occurrence of specified corporate events. The
convertible senior notes will be convertible, regardless of the
foregoing circumstances, on and
after ,
2013 but prior to the close of business on the scheduled trading
day immediately preceding the maturity date of the convertible
senior notes.
The initial conversion rate for the convertible senior notes
will
be shares
of common stock per $1,000 in principal amount of convertible
senior notes (equivalent to an initial conversion price of
approximately $ per share of
common stock). The conversion rate will be subject to adjustment
in some events but will not be adjusted for accrued interest. In
addition, we may be required in certain circumstances to
increase the conversion rate for any convertible senior notes
converted in connection with a make-whole fundamental change (as
defined).
Upon the occurrence of a fundamental change, holders may require
us to repurchase all or a portion of their convertible senior
notes for cash at a price equal to 100% of the principal amount
of the convertible senior notes being repurchased, plus accrued
and unpaid interest, if any.
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Unless we have made an irrevocable net share settlement
election, upon conversion of the convertible senior notes, we
will settle conversions of the convertible senior notes
(i) entirely in shares of our common stock,
(ii) entirely in cash, or (iii) in cash for the
principal amount of the convertible senior notes and shares of
our common stock, or cash and shares of our common stock, for
the excess, if any, of the conversion value above the principal
amount. In addition, at any time on or prior to the
35th scheduled trading day prior to the maturity date of
the convertible senior notes, we may make an irrevocable net
share settlement election pursuant to which we will settle all
future conversions of the convertible senior notes either
(i) entirely in cash or (ii) in cash for the principal
portion amount of convertible senior notes and shares of our
common stock, or cash and shares of our common stock, for the
excess, if any, of the conversion value above the principal
amount. It is our current intent and policy to settle any
conversion of the convertible senior notes in the manner
specified in clause (ii) of the preceding sentence. The
irrevocable net share settlement election is in our sole
discretion and does not require the consent of holders of the
convertible senior notes.
267
DESCRIPTION OF
CAPITAL STOCK
Our authorized capital stock consists of 350,000,000 shares
of common stock, par value $0.01 per share, and
50,000,000 shares of preferred stock, par value $0.01 per
share, the rights and preferences of which may be established
from time to time by our board of directors. As of the date of
this prospectus, there are 86,141,291 outstanding shares of
common stock and no outstanding shares of preferred stock. The
following description of our capital stock does not purport to
be complete and is subject to and qualified by our amended and
restated certificate of incorporation and bylaws, which are
included as exhibits to the registration statement of which this
prospectus forms a part, and by the provisions of applicable
Delaware law.
Common
Stock
Holders of our common stock are entitled to one vote for each
share on all matters voted upon by our stockholders, including
the election of directors, and do not have cumulative voting
rights. Subject to the rights of holders of any then outstanding
shares of our preferred stock, our common stockholders are
entitled to any dividends that may be declared by our board of
directors. Holders of our common stock are entitled to share
ratably in our net assets upon our dissolution or liquidation
after payment or provision for all liabilities and any
preferential liquidation rights of our preferred stock then
outstanding. Holders of our common stock have no preemptive
rights to purchase shares of our stock. The shares of our common
stock are not subject to any redemption provisions and are not
convertible into any other shares of our capital stock. All
outstanding shares of our common stock are fully paid and
nonassessable. The rights, preferences and privileges of holders
of our common stock will be subject to those of the holders of
any shares of our preferred stock we may issue in the future.
Our common stock will be represented by certificates, unless our
board of directors adopts a resolution providing that some or
all of our common stock shall be uncertificated. Any such
resolution will not apply to any shares of common stock that are
already certificated until such shares are surrendered to us.
Preferred
Stock
Our board of directors may, from time to time, authorize the
issuance of one or more series of preferred stock without
stockholder approval. Subject to the provisions of our amended
and restated certificate of incorporation and limitations
prescribed by law, our board of directors is authorized to adopt
resolutions to issue shares, designate the series, establish the
number of shares, change the number of shares constituting any
series, and provide or change the voting powers, preferences and
relative participating, optional and other special rights, and
any qualifications, limitations or restrictions on shares of our
preferred stock, including dividend rights, terms of redemption,
conversion rights and liquidation preferences, in each case
without any action or vote by our stockholders. We have no
current intention to issue any shares of preferred stock.
One of the effects of undesignated preferred stock may be to
enable our board of directors to discourage an attempt to obtain
control of our company by means of a tender offer, proxy
contest, merger or otherwise. The issuance of preferred stock
may adversely affect the rights of our common stockholders by,
among other things:
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restricting dividends on the common stock;
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diluting the voting power of the common stock;
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impairing the liquidation rights of the common stock; or
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delaying or preventing a change in control without further
action by the stockholders.
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Limitation on
Liability and Indemnification of Officers and
Directors
Our amended and restated certificate of incorporation limits the
liability of directors to the fullest extent permitted by
Delaware law. The effect of these provisions is to eliminate the
rights of our company and our stockholders, through
stockholders derivative suits on behalf of our company, to
recover monetary damages against a director for breach of
fiduciary duty as a director, including breaches resulting from
grossly
268
negligent behavior. However, our directors will be personally
liable to us and our stockholders for any breach of the
directors duty of loyalty, for acts or omissions not in
good faith or which involve intentional misconduct or a knowing
violation of law, under Section 174 of the Delaware General
Corporation Law or for any transaction from which the director
derived an improper personal benefit. In addition, our amended
and restated certificate of incorporation and bylaws provide
that we will indemnify our directors and officers to the fullest
extent permitted by Delaware law. We also maintain directors and
officers insurance.
Corporate
Opportunities
Our amended and restated certificate of incorporation provides
that the Goldman Sachs Funds and the Kelso Funds have no
obligation to offer us an opportunity to participate in business
opportunities presented to the Goldman Sachs Funds or the Kelso
Funds or their respective affiliates even if the opportunity is
one that we might reasonably have pursued, and that neither the
Goldman Sachs Funds, the Kelso Funds nor their respective
affiliates will be liable to us or our stockholders for breach
of any duty by reason of any such activities unless, in the case
of any person who is a director or officer of our company, such
business opportunity is expressly offered to such director or
officer in writing solely in his or her capacity as an officer
or director of our company. Stockholders will be deemed to have
notice of and consented to this provision of our certificate of
incorporation.
In addition, the Partnerships partnership agreement
provides that the owners of the managing general partner of the
Partnership, which include the Goldman Sachs Funds and the Kelso
Funds, are permitted to engage in separate businesses which
directly compete with the Partnership and are not required to
share or communicate or offer any potential corporate
opportunities to the Partnership even if the opportunity is one
that we might reasonably have pursued. The agreement provides
that the owners of the managing general partner will not be
liable to the Partnership or any partner for breach of any
fiduciary or other duty by reason of the fact that such person
pursued or acquired for itself any corporate opportunity. See
Risk Factors Risks Related to the Limited
Partnership Structure Through Which We Hold Our Interest in the
Nitrogen Fertilizer Business The managing general
partner of the Partnership has a fiduciary duty to favor the
interests of its owners, and these interests may differ from, or
conflict with, our interests and the interests of our
stockholders.
Delaware
Anti-Takeover Law
Our amended and restated certificate of incorporation provides
that we are not subject to Section 203 of the Delaware
General Corporation Law which regulates corporate acquisitions.
This law provides that specified persons who, together with
affiliates and associates, own, or within three years did own,
15% or more of the outstanding voting stock of a corporation may
not engage in business combinations with the corporation for a
period of three years after the date on which the person became
an interested stockholder. The law defines the term
business combination to include mergers, asset sales
and other transactions in which the interested stockholder
receives or could receive a financial benefit on other than a
pro rata basis with other stockholders.
Removal of
Directors; Vacancies
Our amended and restated certificate of incorporation and bylaws
provide that any director or the entire board of directors may
be removed with or without cause by the affirmative vote of the
majority of all shares then entitled to vote at an election of
directors. Our amended and restated certificate of incorporation
and bylaws also provide that any vacancies on our board of
directors will be filled by the affirmative vote of a majority
of the board of directors then in office, even if less than a
quorum, or by a sole remaining director.
Voting
The affirmative vote of a plurality of the shares of our common
stock present, in person or by proxy will decide the election of
any directors, and the affirmative vote of a majority of the
shares of our common stock present, in person or by proxy will
decide all other matters voted on by stockholders, unless the
question is one upon which, by express provision of law, under
our amended
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and restated certificate of incorporation, or under our bylaws,
a different vote is required, in which case such provision will
control.
Action by
Written Consent
Our amended and restated certificate of incorporation and bylaws
provide that stockholder action can be taken by written consent
of the stockholders only if the Goldman Sachs Funds and the
Kelso Funds collectively beneficially own more than 35.0% of the
outstanding shares of our common stock.
Ability to
Call Special Meetings
Our bylaws provide that special meetings of our stockholders can
only be called pursuant to a resolution adopted by a majority of
our board of directors or by the chairman of our board of
directors. Special meetings may also be called by the holders of
not less than 25% of the outstanding shares of our common stock
if the Goldman Sachs Funds and the Kelso Funds collectively
beneficially own 50% or more of the outstanding shares of our
common stock. Thereafter, stockholders will not be permitted to
call a special meeting or to require our board to call a special
meeting.
Amending Our
Certificate of Incorporation and Bylaws
Our amended and restated certificate of incorporation provides
that our certificate of incorporation may be amended by the
affirmative vote of a majority of the board of directors and by
the affirmative vote of the majority of all shares of our common
stock then entitled to vote at any annual or special meeting of
stockholders. In addition, our amended and restated certificate
of incorporation and bylaws provide that our bylaws may be
amended, repealed or new bylaws may be adopted by the
affirmative vote of a majority of the board of directors or by
the affirmative vote of the majority of all shares of our common
stock then entitled to vote at any annual or special meeting of
stockholders.
Advance Notice
Provisions for Stockholders
In order to nominate directors to our board of directors or
bring other business before an annual meeting of our
stockholders, a stockholders notice must be received by
the Secretary of the Company at the principal executive offices
of the Company not less than 120 calendar days before the date
that our proxy statement is released to stockholders in
connection with the previous years annual meeting of
stockholders, subject to certain exceptions contained in our
bylaws. If no annual meeting was held in the previous year, or
if the date of the applicable annual meeting has been changed by
more than 30 days from the date of the previous years
annual meeting, then a stockholders notice, in order to be
considered timely, must be received by the Secretary of the
Company no later than the later of the 90th day prior to
such annual meeting or the tenth day following the day on which
notice of the date of the annual meeting was mailed or public
disclosure of such date was made.
Listing
Our common stock is listed on the New York Stock Exchange under
the symbol CVI.
Transfer Agent
and Registrar
The transfer agent and registrar for our common stock is
American Stock Transfer & Trust Company.
270
SHARES ELIGIBLE
FOR FUTURE SALE
We have outstanding 86,141,291 shares of common stock. The
23,000,000 shares sold in our initial public offering and
the 27,100 shares of common stock granted to our
non-executive officer employees in connection with our initial
public offering and registered pursuant to a registration
statement on
Form S-8
filed on October 24, 2007 are, and the
10,000,000 shares (11,500,000 shares assuming the
underwriters exercise their option to purchase additional shares
of common stock in full) sold by the selling stockholders in
this offering will be, freely tradable without restriction under
the Securities Act, unless purchased by our
affiliates as that term is defined in Rule 144
under the Securities Act. In general, affiliates include
executive officers, directors and our largest stockholders.
Shares of common stock purchased by affiliates will remain
subject to the resale limitations of Rule 144.
The remaining 53,114,191 shares (51,614,191 shares
assuming the underwriters exercise their option to purchase
additional shares of common stock in full) outstanding following
this offering are restricted securities within the meaning of
Rule 144. Restricted securities may be sold in the public
market only if registered or if they qualify for an exemption
from registration under Rules 144 or 701 promulgated under
the Securities Act, which are summarized below.
The selling stockholders and our directors and officers have
agreed to enter into lock up agreements in connection with this
offering, generally providing that they will not offer, sell,
contract to sell or grant any option to purchase or otherwise
dispose of our common stock or any securities exercisable for or
convertible into our common stock owned by them (other than the
shares of common stock offered hereby) for a period of
90 days after the date of this prospectus without the prior
written consent of the representatives.
Despite possible earlier eligibility for sale under the
provisions of Rules 144 and 701 under the Securities Act,
any shares subject to a
lock-up
agreement will not be salable until the
lock-up
agreement expires or is waived by the representatives. Taking
into account the
lock-up
agreement, and assuming that Coffeyville Acquisition LLC or
Coffeyville Acquisition II LLC are not released from their
lock-up
agreements, the 53,114,191 shares (51,694,191 shares
assuming the underwriters exercise their option to purchase
additional shares of common stock in full) held by our
affiliates will be eligible for future sale in accordance with
the requirements of Rule 144 upon the expiration of the
lockup agreements.
In general, under Rule 144 as currently in effect, after
the expiration of any applicable
lock-up
agreements, an affiliate who has beneficially owned restricted
securities for at least six months would be entitled to sell
within any three month period a number of shares that does not
exceed the greater of the following:
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one percent of the number of shares of common stock then
outstanding, which will equal approximately 861,413 shares
immediately after this offering; or
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the average weekly trading volume of the common stock during the
four calendar weeks preceding the sale.
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Sales by affiliates under Rule 144 are also subject to
manner of sale requirements, notice requirements and the
availability of current public information about us. Under
Rule 144, a person who is not deemed to have been our
affiliate at any time during the three months preceding a sale,
and who has beneficially owned the shares proposed to be sold
for at least six months, is entitled to sell his or her shares
provided he or she complies with the current public information
requirement. After one year, a non-affiliate may freely sell his
or her shares.
271
Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC
and John J. Lipinski, who, assuming all of the shares of common
stock offered hereby are sold, will collectively hold
53,114,191 shares of our common stock
(51,614,191 shares assuming the underwriters exercise their
option to purchase additional shares of common stock in full),
and are parties to registration rights agreements with us.
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, who will hold 52,911,720 shares collectively
(51,411,720 shares assuming the underwriters exercise their
option to purchase additional shares of common stock in full)
can request that we register their shares with the SEC at any
time on up to three occasions each, including pursuant to shelf
registration statements. Mr. Lipinski can piggyback on any
registration statement we file with the SEC.
272
UNITED STATES TAX
CONSEQUENCES TO
NON-UNITED
STATES HOLDERS
The following is a summary of the material United States federal
income and estate tax consequences of the acquisition, ownership
and disposition of our common stock by a
non-U.S. holder.
As used in this summary, the term
non-U.S. holder
means a beneficial owner of our common stock that is not, for
United States federal income tax purposes:
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an individual who is a citizen or resident of the United States
or a former citizen or resident of the United States subject to
taxation as an expatriate;
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a corporation created or organized in or under the laws of the
United States, any state thereof or the District of Columbia;
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a partnership;
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an estate whose income is includible in gross income for
U.S. federal income tax purposes regardless of its
source; or
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a trust, if (1) a United States court is able to exercise
primary supervision over the 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.
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An individual may be treated as a resident of the United States
in any calendar year for United States federal income tax
purposes, instead of a nonresident, by, among other ways, being
present in the United States on at least 31 days in that
calendar year and for an aggregate of at least 183 days
during a three-year period ending in the current calendar year.
For purposes of this calculation, an individual would count all
of the days present in the current year, one-third of the days
present in the immediately preceding year and one-sixth of the
days present in the second preceding year. Residents are taxed
for U.S. federal income purposes as if they were
U.S. citizens.
If an entity or arrangement treated as a partnership or other
type of pass-through entity for U.S. federal income tax
purposes owns our common stock, the tax treatment of a partner
or beneficial owner of such entity may depend upon the status of
the partner or beneficial owner and the activities of the
partnership or entity and by certain determinations made at the
partner or beneficial owner level. Partners and beneficial
owners in such entities that own our common stock should consult
their own tax advisors as to the particular U.S. federal
income and estate tax consequences applicable to them.
This summary does not discuss all of the aspects of
U.S. federal income and estate taxation that may be
relevant to a
non-U.S. holder
in light of the
non-U.S. holders
particular investment or other circumstances. In particular,
this summary only addresses a
non-U.S. holder
that holds our common stock as a capital asset (generally,
investment property) and does not address:
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special U.S. federal income tax rules that may apply to
particular
non-U.S. holders,
such as financial institutions, insurance companies, tax-exempt
organizations, and dealers and traders in securities or
currencies;
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non-U.S. holders
holding our common stock as part of a conversion, constructive
sale, wash sale or other integrated transaction or a hedge,
straddle or synthetic security;
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any U.S. state and local or
non-U.S. or
other tax consequences; and
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the U.S. federal income or estate tax consequences for the
beneficial owners of a
non-U.S. holder.
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This summary is based on provisions of the Code, applicable
United States Treasury regulations and administrative and
judicial interpretations, all as in effect or in existence on
the date of this prospectus. Subsequent developments in United
States federal income or estate tax law, including changes in
law or differing interpretations, which may be applied
retroactively, could have a material effect on the
U.S. federal income and estate tax consequences of
purchasing, owning and disposing
273
of our common stock as set forth in this summary.
Each
non-U.S. holder
should consult a tax advisor regarding the U.S. federal,
state, local and
non-U.S. income
and other tax consequences of acquiring, holding and disposing
of our common stock.
Dividends
We do not anticipate making cash distributions on our common
stock in the foreseeable future. See Dividend
Policy. In the event, however, that we make cash
distributions on our common stock, such distributions will
constitute dividends for United States federal income tax
purposes to the extent paid out of current or accumulated
earnings and profits of the Company. To the extent such
distributions exceed the Companys earnings and profits,
they will be treated first as a return of the stockholders
basis in their common stock to the extent thereof, and then as
gain from the sale of a capital asset. If we make a distribution
that is treated as a dividend and is not effectively connected
with a
non-U.S. holders
conduct of a trade or business in the United States, we will
have to withhold a U.S. federal withholding tax at a rate
of 30%, or a lower rate under an applicable income tax treaty,
from the gross amount of the dividends paid to such
non-U.S. holder.
Non-U.S. holders
should consult their own tax advisors regarding their
entitlement to benefits under a relevant income tax treaty.
In order to claim the benefit of an applicable income tax
treaty, a
non-U.S. holder
will be required to provide a properly executed IRS
Form W-8BEN
(or other applicable form) in accordance with the applicable
certification and disclosure requirements. Special rules apply
to partnerships and other pass-through entities and these
certification and disclosure requirements also may apply to
beneficial owners of partnerships and other pass-through
entities that hold our common stock. A
non-U.S. holder
that is eligible for a reduced rate of U.S. federal
withholding tax under an income tax treaty may obtain a refund
or credit of any excess amounts withheld by filing an
appropriate claim for a refund with the IRS.
Non-U.S. holders
should consult their own tax advisors regarding their
entitlement to benefits under a relevant income tax treaty and
the manner of claiming the benefits.
Dividends that are effectively connected with a
non-U.S. holders
conduct of a trade or business in the United States and, if
required by an applicable income tax treaty, are attributable to
a permanent establishment maintained by the
non-U.S. holder
in the United States, will be taxed on a net income basis at the
regular graduated rates and in the manner applicable to United
States persons. In that case, we will not have to withhold
U.S. federal withholding tax if the
non-U.S. holder
provides a properly executed IRS
Form W-8ECI
(or other applicable form) in accordance with the applicable
certification and disclosure requirements. In addition, a
branch profits tax may be imposed at a 30% rate, or
a lower rate under an applicable income tax treaty, on dividends
received by a foreign corporation that are effectively connected
with the conduct of a trade or business in the United States.
Gain on
disposition of our common stock
A
non-U.S. holder
generally will not be taxed on any gain recognized on a
disposition of our common stock unless:
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the gain is effectively connected with 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;
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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
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we are or have been a U.S. real property holding
corporation for U.S. federal income tax purposes at
any time during the shorter of the five-year period ending on
the date of disposition or the period that the
non-U.S. holder
held our common stock.
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Generally, a corporation is a U.S. real property
holding corporation if the fair market value of its
U.S. real property interests equals or exceeds
50% of the sum of the fair market value of its worldwide real
property interests plus its other assets used or held for use in
a trade or business. We believe that we are not currently, and
we do not anticipate becoming in the future, a U.S. real
property holding corporation. However, because this
determination is made from time to time and is dependent upon a
number of factors, some of which are beyond our control,
including the value of our assets, there can be no assurance
that we will not become a U.S. real property holding
corporation.
However, even if we are or have been a U.S. real property
holding corporation, a
non-U.S. holder
which did not beneficially own, actually or constructively, more
than 5% of the total fair market value of our common stock at
any time during the shorter of the five-year period ending on
the date of disposition or the period that our common stock was
held by the
non-U.S. holder
(a non-5% holder) and which is not otherwise taxed
under any other circumstances described above, generally will
not be taxed on any gain realized on the disposition of our
common stock if, at any time during the calendar year of the
disposition, our common stock was regularly traded on an
established securities market within the meaning of the
applicable United States Treasury regulations.
Our common stock is listed on the New York Stock Exchange.
Although not free from doubt, our common stock should be
considered to be regularly traded on an established securities
market for any calendar quarter during which it is regularly
quoted by brokers or dealers that hold themselves out to buy or
sell our common stock at the quoted price. If our common stock
were not considered to be regularly traded on an established
securities market at any time during the applicable calendar
year, then a non-5% holder would be taxed for U.S. federal
income tax purposes on any gain realized on the disposition of
our common stock on a net income basis as if the gain were
effectively connected with the conduct of a U.S. trade or
business by the non-5% holder during the taxable year and, in
such case, the person acquiring our common stock from a non-5%
holder generally would have to withhold 10% of the amount of the
proceeds of the disposition. Such withholding may be reduced or
eliminated pursuant to a withholding certificate issued by the
IRS in accordance with applicable U.S. Treasury
regulations. We urge all
non-U.S. holders
to consult their own tax advisors regarding the application of
these rules to them.
Federal estate
tax
Our common stock that is owned or treated as owned by an
individual who is not a U.S. citizen or resident of the
United States (as specially defined for U.S. federal estate
tax purposes) at the time of death will be included in the
individuals gross estate for U.S. federal estate tax
purposes, unless an applicable estate tax or other treaty
provides otherwise and, therefore, may be subject to
U.S. federal estate tax.
Information
reporting and backup withholding tax
Dividends paid to a
non-U.S. holder
will be subject to U.S. information reporting and may be
subject to backup withholding. A
non-U.S. holder
will be exempt from backup withholding if the
non-U.S. holder
provides a properly executed IRS
Form W-8BEN
or otherwise meets documentary evidence requirements for
establishing its status as a
non-U.S. holder
or otherwise establishes an exemption.
The gross proceeds from the disposition of our common stock may
be subject to U.S. information reporting and backup
withholding. If a
non-U.S. holder
sells our common stock outside the United States through a
non-U.S. office
of a
non-U.S. broker
and the sales proceeds are paid to the
non-U.S. holder
outside the United States, then the U.S. backup withholding
and information reporting requirements generally will not apply
to that payment. However, United States information reporting,
but not U.S. backup withholding, will apply to a payment of
sales proceeds, even if that payment is
275
made outside the United States, if a
non-U.S. holder
sells our common stock through a
non-U.S. office
of a broker that:
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is a United States person;
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derives 50% or more of its gross income in specific periods from
the conduct of a trade or business in the United States;
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is a controlled foreign corporation for
U.S. federal income tax purposes; or
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is a foreign partnership, if at any time during its tax year:
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one or more of its partners are United States persons who in the
aggregate hold more than 50% of the income or capital interests
in the partnership; or
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the foreign partnership is engaged in a U.S. trade or
business,
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unless the broker has documentary evidence in its files that the
non-U.S. holder
is not a United States person and certain other conditions are
met or the
non-U.S. holder
otherwise establishes an exemption.
If a
non-U.S. holder
receives payments of the proceeds of a sale of our common stock
to or through a United States office of a broker, the payment is
subject to both U.S. backup withholding and information
reporting unless the
non-U.S. holder
provides a properly executed IRS
Form W-8BEN
certifying that the
non-U.S. Holder
is not a United States person or the
non-U.S. holder
otherwise establishes an exemption.
A
non-U.S. holder
generally may obtain a refund of any amounts withheld under the
backup withholding rules that exceed the
non-U.S. holders
U.S. federal income tax liability by filing a refund claim
with the IRS.
276
UNDERWRITING
The Company, the selling stockholders and the underwriters will
enter into an underwriting agreement with respect to the shares
being offered. Subject to certain conditions, each underwriter
has severally agreed to purchase the number of shares indicated
in the following table. Goldman, Sachs & Co. and
Deutsche Bank Securities Inc. are the joint book-running
managers for this offering and the representatives of the
underwriters.
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Underwriters
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Number of Shares
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Goldman, Sachs & Co.
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Deutsche Bank Securities Inc.
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Citigroup Global Markets Inc.
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Credit Suisse Securities (USA) LLC
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Total
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10,000,000
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The underwriters are committed to take and pay for all of the
shares being offered, if any are taken, other than the shares
covered by the option described below unless and until this
option is exercised. We expect that the underwriting agreement
will provide that the obligations of the underwriters to take
and pay for the shares are subject to a number of conditions,
including, among others, the accuracy of the Companys and
the selling stockholders representations and warranties in
the underwriting agreement, receipt of specified letters from
counsel and the Companys independent registered public
accounting firm, and receipt of specified officers
certificates.
To the extent that the underwriters sell more than
10,000,000 shares, the underwriters have an option to buy
up to an additional 1,500,000 shares of common stock from
certain of the selling stockholders to cover such sales. They
may exercise that option for 30 days. If any shares are
purchased pursuant to this option, the underwriters will
severally purchase shares from each of Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC pro rata in
approximately the same proportion as set forth in the table
above.
The following table shows the per share and total underwriting
discounts and commissions to be paid to the underwriters by the
selling stockholders. These amounts are shown assuming both no
exercise and full exercise of the underwriters option to
purchase 1,500,000 additional shares of common stock.
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No Exercise
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Full Exercise
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Per Share
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$
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$
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Total
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$
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$
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Shares sold by the underwriters to the public will initially be
offered at the initial public offering price set forth on the
cover page of this prospectus. Any shares sold by the
underwriters to securities dealers may be sold at a discount of
up to $ per share from the initial
public offering price. If all of the shares are not sold at the
initial public offering price, the representatives may change
the offering price and the other selling terms. The offering of
the shares by the underwriters is subject to receipt and
acceptance and subject to the underwriters right to reject
any order in whole or in part.
The Company, the selling stockholders and our directors and
executive officers have agreed with the underwriters, subject to
exceptions, not to dispose of or hedge any of the shares of
common stock or securities convertible into or exchangeable for
shares of common stock during the period from the date of this
prospectus continuing through the date 90 days after the
date of this prospectus, except with the prior written consent
of the representatives. This agreement does not apply to any
existing employee benefit plans or shares issued in connection
with acquisitions or business transactions. See Shares
Eligible for Future Sale for a discussion of specified
transfer restrictions.
The underwriters have informed us that they do not presently
intend to release shares or other securities subject to the
lock-up
agreements. Any determination to release any shares subject to
the
lock-up
agreements would be based on a number of factors at the time of
any such determination;
277
such factors may include the market price of the common stock,
the liquidity of the trading market for the common stock,
general market conditions, the number of shares proposed to be
sold, and the timing, purpose and terms of the proposed sale.
Our common stock is listed on the New York Stock Exchange under
the symbol CVI.
In connection with this offering, the underwriters may purchase
and sell shares of the common stock in the open market. These
transactions may include short sales, stabilizing transactions
and purchases to cover positions created by short sales. Short
sales involve the sale by the underwriters of a greater number
of shares than they are required to purchase in this offering.
Covered short sales are sales made in an amount not
greater than the underwriters option to purchase
additional shares from us in this offering. The underwriters may
close out any covered short position by either exercising their
option to purchase additional shares or purchasing shares in the
open market. In determining the source of shares to close out
the covered short position, the underwriters will consider,
among other things, the price of shares available for purchase
in the open market as compared to the price at which they may
purchase additional shares pursuant to the option granted to
them. Naked short sales are any sales in excess of
that option. The underwriters must close out any naked short
position by purchasing shares in the open market. A naked short
position is more likely to be created if the underwriters are
concerned that there may be downward pressure on the price of
the shares of common stock in the open market after pricing that
could adversely affect investors who purchase in this offering.
Stabilizing transactions consist of various bids for or
purchases of shares of common stock made by the underwriters in
the open market prior to the completion of this offering.
The underwriters may also impose a penalty bid. This occurs when
a particular underwriter repays to the underwriters a portion of
the underwriting discount received by it because the
representatives have repurchased shares sold by or for the
account of that underwriter in stabilizing or short covering
transactions.
Purchases to cover a short position and stabilizing transactions
may have the effect of preventing or retarding a decline in the
market price of the shares of common stock and, together with
the imposition of the penalty bid, may stabilize, maintain or
otherwise affect the market price of the shares of common stock.
As a result, the price of the shares of common stock may be
higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be
discontinued at any time. These transactions may be effected on
the NYSE, in the over-the-counter market or otherwise.
Each underwriter has represented and agreed that:
(a) it has only communicated or caused to be communicated
and will only communicate or cause to be communicated an
invitation or inducement to engage in investment activity
(within the meaning of Section 21 of the FSMA) received by
it in connection with the issue or sale of the shares in
circumstances in which Section 21(1) of the FSMA does not
apply to the Company; and
(b) it has complied and will comply with all applicable
provisions of the FSMA with respect to anything done by it in
relation to the shares in, from or otherwise involving the
United Kingdom.
In relation to each Member State of the European Economic Area
which has implemented the Prospectus Directive (each, a Relevant
Member State), each underwriter has represented and agreed that
with effect from and including the date on which the Prospectus
Directive is implemented in that Relevant Member State (the
Relevant Implementation Date) it has not made and will not make
an offer of shares to the public in that Relevant Member State
prior to the publication of a prospectus in relation to the
shares which has been approved by the competent authority in
that Relevant Member State or, where appropriate, approved in
another Relevant Member State and notified to the competent
authority in that Relevant Member State, all in accordance with
the Prospectus Directive, except that it may, with effect from
and including the Relevant Implementation Date, make an offer of
shares to the public in that Relevant Member State at any time:
(a) to legal entities which are authorized or regulated to
operate in the financial markets or, if not so authorized or
regulated, whose corporate purpose is solely to invest in
securities;
278
(b) to any legal entity which has two or more of
(1) an average of at least 250 employees during the
last financial year; (2) a total balance sheet of more than
43,000,000 and (3) an annual net turnover of more
than 50,000,000, as shown in its last annual or
consolidated accounts;
(c) to fewer than 100 natural or legal persons (other than
qualified investors as defined in the Prospectus Directive)
subject to obtaining the prior consent of the representatives
for any such offer; or
(d) in any other circumstances which do not require the
publication by the Company of a prospectus pursuant to
Article 3 of the Prospectus Directive.
For the purposes of this provision, the expression an
offer of shares to the public in relation to any
shares in any Relevant Member State means the communication in
any form and by any means of sufficient information on the terms
of the offer and the shares to be offered so as to enable an
investor to decide to purchase or subscribe the shares, as the
same may be varied in that Relevant Member State by any measure
implementing the Prospectus Directive in that Relevant Member
State and the expression Prospectus Directive means Directive
2003/71/EC and includes any relevant implementing measure in
each Relevant Member State.
The shares may not be offered or sold by means of any document
other than (i) in circumstances which do not constitute an
offer to the public within the meaning of the Companies
Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to
professional investors within the meaning of the
Securities and Futures Ordinance (Cap. 571, Laws of Hong
Kong) and any rules made thereunder, or (iii) in other
circumstances which do not result in the document being a
prospectus within the meaning of the Companies
Ordinance (Cap. 32, Laws of Hong Kong), and no
advertisement, invitation or document relating to the shares may
be issued or may be in the possession of any person for the
purpose of issue (in each case whether in Hong Kong or
elsewhere), which is directed at, or the contents of which are
likely to be accessed or read by, the public in Hong Kong
(except if permitted to do so under the laws of Hong Kong) other
than with respect to shares which are or are intended to be
disposed of only to persons outside Hong Kong or only to
professional investors within the meaning of the
Securities and Futures Ordinance (Cap. 571, Laws of Hong
Kong) and any rules made thereunder.
This prospectus has not been registered as a prospectus with the
Monetary Authority of Singapore. Accordingly, this prospectus
and any other document or material in connection with the offer
or sale, or invitation for subscription or purchase, of the
shares may not be circulated or distributed, nor may the shares
be offered or sold, or be made the subject of an invitation for
subscription or purchase, whether directly or indirectly, to
persons in Singapore other than (1) to an institutional
investor under Section 274 of the Securities and Futures
Act, Chapter 289 of Singapore, or the SFA, (2) to a
relevant person, or any person pursuant to Section 275(1A),
and in accordance with the conditions, specified in
Section 275 of the SFA or (3) otherwise pursuant to,
and in accordance with the conditions of, any other applicable
provision of the SFA.
Where the shares are subscribed or purchased under
Section 275 by a relevant person which is: (a) a
corporation (which is not an accredited investor) the sole
business of which is to hold investments and the entire share
capital of which is owned by one or more individuals, each of
whom is an accredited investor; or (b) a trust (where the
trustee is not an accredited investor) whose sole purpose is to
hold investments and each beneficiary is an accredited investor,
shares, debentures and units of shares and debentures of that
corporation or the beneficiaries rights and interest in
that trust shall not be transferable for 6 months after
that corporation or that trust has acquired the shares under
Section 275 except: (1) to an institutional investor
under Section 274 of the SFA or to a relevant person, or
any person pursuant to Section 275(1A), and in accordance
with the conditions, specified in Section 275 of the SFA;
(2) where no consideration is given for the transfer; or
(3) by operation of law.
The securities have not been and will not be registered under
the Securities and Exchange Law of Japan (the Securities
and Exchange Law) and each underwriter has agreed that it
will not offer or sell any securities, directly or indirectly,
in Japan or to, or for the benefit of, any resident of Japan
279
(which term as used herein means any person resident in Japan,
including any corporation or other entity organized under the
laws of Japan), or to others for re-offering or resale, directly
or indirectly, in Japan or to a resident of Japan, except
pursuant to an exemption from the registration requirements of,
and otherwise in compliance with, the Securities and Exchange
Law and any other applicable laws, regulations and ministerial
guidelines of Japan.
The Company estimates that its share of the total expenses of
this offering will be approximately $1.3 million.
The Company and the selling stockholders have agreed to
indemnify the several underwriters against specified
liabilities, including liabilities under the Securities Act.
Affiliates of Goldman, Sachs & Co. own more than 10% of the
Companys outstanding common stock. As a result, Goldman,
Sachs & Co. is deemed to be an affiliate of the Company
under Rule 2720(b)(1) of the NASD Conduct Rules and is
deemed to have a conflict of interest under Rule 2720 of
the NASD Conduct Rules. Accordingly, this offering will be made
in compliance with the applicable provisions of Rule 2720 of the
NASD Conduct Rules as required by Rule 2720 of the NASD
Conduct Rules.
Coffeyville Acquisition II LLC, a selling stockholder and an
affiliate of Goldman, Sachs & Co., will receive a portion
of the net proceeds of this offering.
Certain of the underwriters and their respective affiliates
have, from time to time, performed, and may in the future
perform, various financial advisory, investment banking,
commercial banking and other services for our company, for which
they received or will receive customary fees and expenses.
Furthermore, certain of the underwriters and their respective
affiliates may, from time to time, enter into arms-length
transactions with us in the ordinary course of their business.
Goldman Sachs Credit Partners L.P. and Credit Suisse Securities
(USA) LLC are joint lead arrangers and joint bookrunners under
our Credit Facility, Credit Suisse is the administrative agent
and Deutsche Bank Trust Company Americas is the syndication
agent under our Credit Facility. Goldman Sachs Credit Partners
L.P., Deutsche Bank Securities Inc., Credit Suisse and Citicorp
North America, Inc. are lenders under the Credit Facility. In
addition, each of the underwriters for this offering is also
participating in our concurrent offering of convertible senior
notes.
For a description of other transactions between us and Goldman,
Sachs & Co. and its affiliates, including payments of
dividends and payments under our credit facilities by us to such
affiliates and director designation rights, see Certain
Relationships and Related Party Transactions and The
Nitrogen Fertilizer Limited Partnership.
280
LEGAL
MATTERS
The validity of the shares of common stock offered by this
prospectus will be passed upon for our company by Fried, Frank,
Harris, Shriver & Jacobson LLP, New York, New York.
Debevoise & Plimpton LLP, New York, New York is acting
as counsel to the underwriters. Debevoise & Plimpton
LLP has in the past provided, and continues to provide, legal
services to Kelso & Company, including relating to
Coffeyville Acquisition LLC.
EXPERTS
The consolidated financial statements of CVR Energy, Inc. and
subsidiaries, which we refer to as Successor, collectively refer
to the consolidated financial statements for the
174-day
period ended June 23, 2005 for Coffeyville Group Holdings,
LLC and subsidiaries, excluding Leiber Holdings LLC, as
discussed in note 1 to the consolidated financial
statements, which we refer to as Immediate Predecessor, and the
consolidated financial statements as of December 31, 2006
and 2007 and for the
233-day
period ended December 31, 2005 for Successor have been
included herein (and in the registration statement) in reliance
upon the report of KPMG LLP, independent registered public
accounting firm, appearing elsewhere herein, and upon the
authority of said firm as experts in accounting and auditing.
The audit report covering the consolidated financial statements
of CVR Energy, Inc. and subsidiaries noted above contains an
explanatory paragraph that states that as discussed in
note 1 to the consolidated financial statements, effective
June 24, 2005, Successor acquired the net assets of
Immediate Predecessor in a business combination accounted for as
a purchase. As a result of these acquisitions, the consolidated
financial statements for the periods after the acquisitions are
presented on a different cost basis than that for the periods
before the acquisitions and, therefore, are not comparable. The
audit report also contains an explanatory paragraph that states
as discussed in note 2 to the consolidated financial
statements, the Company has restated the accompanying
consolidated financial statements as of and for the year ended
December 31, 2007.
WHERE YOU CAN
FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-1
under the Securities Act with respect to the common stock. This
prospectus does not contain all of the information set forth in
the registration statement and the exhibits and schedules to the
registration statement. For further information with respect to
us and our common stock, we refer you to the registration
statement and the exhibits and schedules filed as a part of the
registration statement. Statements contained in this prospectus
concerning the contents of any contract or any other document
are not necessarily complete. If a contract or document has been
filed as an exhibit to the registration statement, we refer you
to the copy of the contract or document that has been filed as
an exhibit and reference thereto is qualified in all respects by
the terms of the filed exhibit. The registration statement,
including exhibits and schedules, may be inspected without
charge at the Public Reference Room of the SEC at
100 F Street, N.E., Washington, D.C. 20549, and
copies of all or any part of it may be obtained from that office
after payment of fees prescribed by the SEC. Information on the
operation of the Public Reference Room may be obtained by
calling the SEC at
1-800-SEC-0330.
The SEC maintains a web site that contains reports, proxy and
information statements and other information regarding
registrants that file electronically with the SEC at
http://www.sec.gov.
281
GLOSSARY OF
SELECTED TERMS
The following are definitions of certain industry terms used in
this prospectus.
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2-1-1 crack spread
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The approximate gross margin resulting from processing two
barrels of crude oil to produce one barrel of gasoline and one
barrel of heating oil.
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Barrel
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Common unit of measure in the oil industry which equates to 42
gallons.
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Blendstocks
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Various compounds that are combined with gasoline or diesel from
the crude oil refining process to make finished gasoline and
diesel fuel; these may include natural gasoline, FCC unit
gasoline, ethanol, reformate or butane, among others.
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bpd
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Abbreviation for barrels per day.
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Btu
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British thermal units: a measure of energy. One Btu of heat is
required to raise the temperature of one pound of water one
degree Fahrenheit.
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Bulk sales
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Volume sales through third party pipelines, in contrast to
tanker truck quantity sales.
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By-products
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Products that result from extracting high value products such as
gasoline and diesel fuel from crude oil; these include black
oil, sulfur, propane, pet coke and other products.
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Capacity
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Capacity is defined as the throughput a process unit is capable
of sustaining, either on a calendar or stream day basis. The
throughput may be expressed in terms of maximum sustainable,
nameplate or economic capacity. The maximum sustainable or
nameplate capacities may not be the most economical. The
economic capacity is the throughput that generally provides the
greatest economic benefit based on considerations such as
feedstock costs, product values and downstream unit constraints.
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Catalyst
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A substance that alters, accelerates, or instigates chemical
changes, but is neither produced, consumed nor altered in the
process.
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Coker unit
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A refinery unit that utilizes the lowest value component of
crude oil remaining after all higher value products are removed,
further breaks down the component into more valuable products
and converts the rest into pet coke.
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Common units
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The class of interests issued or to be issued under the limited
liability company agreements governing Coffeyville Acquisition
LLC, Coffeyville Acquisition II LLC and Coffeyville
Acquisition III LLC, which provide for voting rights and
have rights with respect to profits and losses of, and
distributions from, the respective limited liability companies.
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Corn belt
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The primary corn producing region of the United States, which
includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska,
Ohio and Wisconsin.
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Crack spread
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A simplified calculation that measures the difference between
the price for light products and crude oil. For example, 2-1-1
crack spread is often referenced and represents the approximate
gross margin resulting from processing two barrels of crude oil
to produce one barrel of gasoline and one barrel of diesel fuel.
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Crude slate
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The mix of different crude types (qualities) being charged to a
crude unit.
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282
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Crude slate optimization
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The process of determining the most economic crude oils to be
refined based upon the prevailing product values, crude prices,
crude oil yields and refinery process unit operating unit
constraints to maximize profit.
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Crude unit
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The initial refinery unit to process crude oil by separating the
crude oil according to boiling point under high heat to recover
various hydrocarbon fractions.
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Distillates
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Primarily diesel fuel, kerosene and jet fuel.
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Ethanol
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A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is
typically produced chemically from ethylene, or biologically
from fermentation of various sugars from carbohydrates found in
agricultural crops and cellulosic residues from crops or wood.
It is used in the United States as a gasoline octane enhancer
and oxygenate.
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Farm belt
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Refers to the states of Illinois, Indiana, Iowa, Kansas,
Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma,
South Dakota, Texas and Wisconsin.
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Feedstocks
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Petroleum products, such as crude oil and natural gas liquids,
that are processed and blended into refined products.
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Fluid catalytic cracking unit
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Converts gas oil from the crude unit or coker unit into
liquefied petroleum gas, distillates and gasoline blendstocks by
applying heat in the presence of a catalyst.
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Fluxant
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Material added to coke to aid in the removal of coke metal
impurities from the gasifier. The material consists of a mixture
of fly ash and sand.
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Heavy crude oil
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A relatively inexpensive crude oil characterized by high
relative density and viscosity. Heavy crude oils require greater
levels of processing to produce high value products such as
gasoline and diesel fuel.
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Independent refiner
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A refiner that does not have crude oil exploration or production
operations. An independent refiner purchases the crude oil used
as feedstock in its refinery operations from third parties.
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Jobber
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A person or company that purchases quantities of refined fuel
from refining companies, either for sale to retailers or to sell
directly to the users of those products.
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Light crude oil
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A relatively expensive crude oil characterized by low relative
density and viscosity. Light crude oils require lower levels of
processing to produce high value products such as gasoline and
diesel fuel.
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Liquefied petroleum gas
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Light hydrocarbon material gaseous at atmospheric temperature
and pressure, held in the liquid state by pressure to facilitate
storage, transport and handling.
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Magellan Midstream Partners L.P.
|
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A publicly traded company whose business is the transportation,
storage and distribution of refined petroleum products.
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Maya
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A heavy, sour crude oil from Mexico characterized by an API
gravity of approximately 22.0 and a sulfur content of
approximately 3.3 weight percent.
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Midcontinent
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Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and
Iowa.
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283
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Modified Solomon complexity
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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.
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MMBtu
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One million British thermal units: a measure of energy. One Btu
of heat is required to raise the temperature of one pound of
water one degree Farenheit.
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Naphtha
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The major constituent of gasoline fractionated from crude oil
during the refining process, which is later processed in the
reformer unit to increase octane.
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Netbacks
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Refers to the unit price of fertilizer, in dollars per ton,
offered on a delivered basis and excludes shipment costs. Also
referred to as plant gate price.
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Operating units
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Override units granted pursuant to the limited liability company
agreements governing Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, which vest based on service.
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Override units
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The class of interests issued or to be issued under the limited
liability company agreements governing Coffeyville Acquisition
LLC, Coffeyville Acquisition II LLC and Coffeyville
Acquisition III LLC, which represent profits interests in
the respective limited liability companies. With respect to the
override units issued under the limited liability company
agreements of Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, the units are classified as either
operating units or value units.
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PADD I
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East Coast Petroleum Area for Defense District which includes
Connecticut, Delaware, District of Columbia, Florida, Georgia,
Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New
York, North Carolina, Pennsylvania, Rhode Island, South
Carolina, Vermont, Virginia and West Virginia.
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PADD II
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Midwest Petroleum Area for Defense District which includes
Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota,
Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota,
Tennessee, and Wisconsin.
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PADD III
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Gulf Coast Petroleum Area for Defense District which includes
Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas.
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PADD IV
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Rocky Mountains Petroleum Area for Defense District which
includes Colorado, Idaho, Montana, Utah, and Wyoming.
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PADD V
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West Coast Petroleum Area for Defense District which includes
Alaska, Arizona, California, Hawaii, Nevada, Oregon, and
Washington.
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Pet coke
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A coal-like substance that is produced during the refining
process.
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Phantom performance points
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Phantom points granted or to be granted pursuant to the Phantom
Unit Plan I and Phantom Unit Plan II, which vest based on
performance of the investment made by Coffeyville Acquisition
LLC and Coffeyville Acquisition II LLC, respectively.
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284
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Phantom points
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The class of interests to be issued under the Phantom Unit
Plan I, and to be issued under the Phantom Unit Plan II,
which represent or will represent the opportunity to receive a
cash payment when distributions of profit are made pursuant to
the limited liability company agreements of Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC. Phantom
points are classified as either phantom service points or
phantom performance points.
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Phantom service points
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Phantom points granted or to be granted pursuant to the Phantom
Unit Plan I and Phantom Unit Plan II, which vest based on
service.
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Phantom Unit Plan I
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The Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan I), which relates to distributions made by Coffeyville
Acquisition LLC.
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Phantom Unit Plan II
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The Coffeyville Resources, LLC Phantom Unit Appreciation Plan
(Plan I), which relates to distributions made by Coffeyville
Acquisition II LLC.
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Profits interests
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Interests in the profits of Coffeyville Acquisition LLC,
Coffeyville Acquisition II LLC and Coffeyville
Acquisition III LLC, also referred to as override
units.
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Rack sales
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Sales which are made into tanker truck (versus bulk pipeline
batcher) via either a proprietary or third terminal facility
designed for truck loading.
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Recordable incident
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An injury, as defined by OSHA. All work-related deaths and
illnesses, and those work-related injuries which result in loss
of consciousness, restriction of work or motion, transfer to
another job, or require medical treatment beyond first aid.
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Recordable injury rate
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The number of recordable injuries per 200,000 hours rate
worked.
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Refined products
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Petroleum products, such as gasoline, diesel fuel and jet fuel,
that are produced by a refinery.
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Refining margin
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A measurement calculated as the difference between net sales and
cost of products sold (exclusive of depreciation and
amortization).
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Reformer unit
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A refinery unit that processes naphtha and converts it to
high-octane gasoline by using a platinum/rhenium catalyst. Also
known as a platformer.
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Reformulated gasoline
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Gasoline with compounds or properties which meet the
requirements of the reformulated gasoline regulations.
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Slag
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A glasslike substance removed from the gasifier containing the
metal impurities originally present in the coke.
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Slurry
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A byproduct of the fluid catalytic cracking process that is sold
for further processing or blending with fuel oil.
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Sour crude oil
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A crude oil that is relatively high in sulfur content, requiring
additional processing to remove the sulfur. Sour crude oil is
typically less expensive than sweet crude oil.
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Spot market
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A market in which commodities are bought and sold for cash and
delivered immediately.
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Sweet crude oil
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A crude oil that is relatively low in sulfur content, requiring
less processing to remove the sulfur. Sweet crude oil is
typically more expensive than sour crude oil.
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285
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Syngas
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A mixture of gases (largely carbon monoxide and hydrogen) that
results from heating coal in the presence of steam.
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Throughput
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The volume processed through a unit or a refinery.
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Ton
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One ton is equal to 2,000 pounds.
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Turnaround
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A periodically required standard procedure to refurbish and
maintain a refinery that involves the shutdown and inspection of
major processing units and occurs every three to four years.
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UAN
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UAN is a solution of urea and ammonium nitrate in water used as
a fertilizer.
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Utilization
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Ratio of total refinery throughput to the rated capacity of the
refinery.
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Vacuum unit
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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.
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Value units
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Override units granted pursuant to the limited liability company
agreements governing Coffeyville Acquisition LLC and Coffeyville
Acquisition II LLC, which vest based on performance of the
investment made by Coffeyville Acquisition LLC or Coffeyville
Acquisition II LLC, respectively.
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Wheat belt
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The primary wheat producing region of the United States, which
includes Oklahoma, Kansas, North Dakota, South Dakota and Texas.
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WTI
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West Texas Intermediate crude oil, a light, sweet crude oil,
characterized by an API gravity between 39 and 41 and a sulfur
content of approximately 0.4 weight percent that is used as a
benchmark for other crude oils.
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WTS
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West Texas Sour crude oil, a relatively light, sour crude oil
characterized by an API gravity of 30-32 degrees and a sulfur
content of approximately 2.0 weight percent.
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Yield
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The percentage of refined products that is produced from crude
and other feedstocks.
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286
CVR ENERGY, INC.
AND SUBSIDIARIES
Index to
Consolidated Financial Statements
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Audited Consolidated Financial Statements:
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Report of Independent Registered Public Accounting Firm
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F-2
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Consolidated Balance Sheets as of December 31, 2006 and
December 31, 2007
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F-3
|
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Consolidated Statements of Operations for the
174-day
period ended June 23, 2005, for the
233-day
period ended December 31, 2005, and for the years ended
December 31, 2006 and December 31, 2007
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F-4
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Consolidated Statements of Changes in Stockholders
Equity/Members Equity for the
174-day
period ended June 23, 2005, for the
233-day
period ended December 31, 2005, and for the years ended
December 31, 2006 and December 31, 2007
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F-5
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|
Consolidated Statements of Cash Flows for the
174-day
period ended June 23, 2005, for the
233-day
period ended December 31, 2005, and for the years ended
December 31, 2006 and December 31, 2007
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F-9
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Notes to Consolidated Financial Statements
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F-10
|
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Unaudited Condensed Consolidated Financial Statements:
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|
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Condensed Consolidated Balance Sheets as of March 31, 2008
and December 31, 2007 (unaudited)
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F-65
|
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Condensed Consolidated Statements of Operations for the three
months ended March 31, 2008 (unaudited) and the three
months ended March 31, 2007 (unaudited)
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F-66
|
|
Condensed Consolidated Statements of Cash Flows for the three
months ended March 31, 2008 (unaudited) and the three
months ended March 31, 2007 (unaudited)
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F-67
|
|
Notes to Condensed Consolidated Financial Statements (unaudited)
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F-68
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F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of
Directors
CVR Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
CVR Energy, Inc. and subsidiaries (the Successor) as of
December 31, 2006 and 2007, and the related statements of
operations, changes in stockholders equity/members
equity, and cash flows for Coffeyville Group Holdings, LLC and
subsidiaries, excluding Leiber Holdings, LLC, (the Predecessor)
for the
174-day
period ended June 23, 2005, and for the Successor for the
233-day
period ended December 31, 2005 and for the years ended
December 31, 2006 and 2007, as discussed in note 1 to
the consolidated financial statements. These consolidated
financial statements are the responsibility of the
Successors management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of the Successor as of December 31, 2006 and 2007,
and the results of the Predecessors operations and its
cash flows for the
174-day
period ended June 23, 2005 and the results of the
Successors operations and its cash flows for the
233-day
period ended December 31, 2005 and for the years ended
December 31, 2006 and 2007, in conformity with U.S.
generally accepted accounting principles.
As discussed in note 1 to the consolidated financial
statements, effective June 24, 2005, the Successor acquired
the net assets of the Predecessor in a business combination
accounted for as a purchase. As a result of this acquisition,
the consolidated financial statements for the periods after the
acquisition are presented on a different cost basis than that
for the period before the acquisition and, therefore, are not
comparable.
As discussed in note 2 to the consolidated financial
statements, the Company has restated the accompanying
consolidated financial statements as of and for the year ended
December 31, 2007.
KPMG LLP
Kansas City, Missouri
March 28, 2008, except as to note 2, which is as of
May 8, 2008
F-2
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Balance Sheets
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December 31,
|
|
|
December 31,
|
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|
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2006
|
|
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2007
|
|
|
|
(In thousands of dollars)
|
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As restated()
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ASSETS
|
Current assets:
|
|
|
|
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|
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|
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Cash and cash equivalents
|
|
$
|
41,919
|
|
|
$
|
30,509
|
|
Accounts receivable, net of allowance for doubtful accounts of
$375 and $391, respectively
|
|
|
69,589
|
|
|
|
86,546
|
|
Inventories
|
|
|
161,433
|
|
|
|
254,655
|
|
Prepaid expenses and other current assets
|
|
|
18,525
|
|
|
|
14,186
|
|
Insurance receivable
|
|
|
|
|
|
|
73,860
|
|
Income tax receivable
|
|
|
32,099
|
|
|
|
31,367
|
|
Deferred income taxes
|
|
|
18,889
|
|
|
|
79,047
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
342,454
|
|
|
|
570,170
|
|
Property, plant, and equipment, net of accumulated depreciation
|
|
|
1,007,156
|
|
|
|
1,192,174
|
|
Intangible assets, net
|
|
|
638
|
|
|
|
473
|
|
Goodwill
|
|
|
83,775
|
|
|
|
83,775
|
|
Deferred financing costs, net
|
|
|
9,128
|
|
|
|
7,515
|
|
Insurance receivable
|
|
|
|
|
|
|
11,400
|
|
Other long-term assets
|
|
|
6,329
|
|
|
|
2,849
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,449,480
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
5,798
|
|
|
$
|
4,874
|
|
Note payable and capital lease obligations
|
|
|
|
|
|
|
11,640
|
|
Payable to swap counterparty
|
|
|
36,895
|
|
|
|
262,415
|
|
Accounts payable
|
|
|
138,911
|
|
|
|
182,225
|
|
Personnel accruals
|
|
|
24,731
|
|
|
|
36,659
|
|
Accrued taxes other than income taxes
|
|
|
9,035
|
|
|
|
14,732
|
|
Deferred revenue
|
|
|
8,812
|
|
|
|
13,161
|
|
Other current liabilities
|
|
|
6,019
|
|
|
|
33,820
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
230,201
|
|
|
|
559,526
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
769,202
|
|
|
|
484,328
|
|
Accrued environmental liabilities
|
|
|
5,395
|
|
|
|
4,844
|
|
Deferred income taxes
|
|
|
284,123
|
|
|
|
286,986
|
|
Other long-term liabilities
|
|
|
|
|
|
|
1,122
|
|
Payable to swap counterparty
|
|
|
72,806
|
|
|
|
88,230
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
1,131,526
|
|
|
|
865,510
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Minority interest in subsidiaries
|
|
|
4,326
|
|
|
|
10,600
|
|
Management voting common units subject to redemption,
201,063 units issued and outstanding in 2006
|
|
|
6,981
|
|
|
|
|
|
Stockholders equity/members equity
|
|
|
|
|
|
|
|
|
Voting common units, 22,614,937 units issued and
outstanding in 2006
|
|
|
73,593
|
|
|
|
|
|
Management nonvoting override units, 2,976,353 units issued
and outstanding in 2006
|
|
|
2,853
|
|
|
|
|
|
Common Stock $0.01 par value per share,
350,000,000 shares authorized; 86,141,291 shares
issued and outstanding
|
|
|
|
|
|
|
861
|
|
Additional
paid-in-capital
|
|
|
|
|
|
|
458,359
|
|
Retained deficit
|
|
|
|
|
|
|
(26,500
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity/members equity
|
|
|
76,446
|
|
|
|
432,720
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity/members
equity
|
|
$
|
1,449,480
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated
financial statements.
|
See accompanying notes to consolidated financial statements.
F-3
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate Predecesssor
|
|
|
|
Successor
|
|
|
|
174 Days Ended
|
|
|
|
233 Days Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
(in thousands except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As restated()
|
|
Net sales
|
|
$
|
980,706
|
|
|
|
$
|
1,454,260
|
|
|
$
|
3,037,567
|
|
|
$
|
2,966,865
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
768,067
|
|
|
|
|
1,168,137
|
|
|
|
2,443,374
|
|
|
|
2,308,740
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
80,914
|
|
|
|
|
85,313
|
|
|
|
198,980
|
|
|
|
276,138
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
18,342
|
|
|
|
|
18,320
|
|
|
|
62,600
|
|
|
|
93,122
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,523
|
|
Depreciation and amortization
|
|
|
1,128
|
|
|
|
|
23,954
|
|
|
|
51,005
|
|
|
|
60,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
868,451
|
|
|
|
|
1,295,724
|
|
|
|
2,755,959
|
|
|
|
2,780,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
112,255
|
|
|
|
|
158,536
|
|
|
|
281,608
|
|
|
|
186,563
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(7,802
|
)
|
|
|
|
(25,007
|
)
|
|
|
(43,880
|
)
|
|
|
(61,126
|
)
|
Interest income
|
|
|
512
|
|
|
|
|
972
|
|
|
|
3,450
|
|
|
|
1,100
|
|
Gain (loss) on derivatives
|
|
|
(7,665
|
)
|
|
|
|
(316,062
|
)
|
|
|
94,493
|
|
|
|
(281,978
|
)
|
Loss on extinguishment of debt
|
|
|
(8,094
|
)
|
|
|
|
|
|
|
|
(23,360
|
)
|
|
|
(1,258
|
)
|
Other income (expense)
|
|
|
(761
|
)
|
|
|
|
(564
|
)
|
|
|
(900
|
)
|
|
|
356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(23,810
|
)
|
|
|
|
(340,661
|
)
|
|
|
29,803
|
|
|
|
(342,906
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
|
88,445
|
|
|
|
|
(182,125
|
)
|
|
|
311,411
|
|
|
|
(156,343
|
)
|
Income tax expense (benefit)
|
|
|
36,048
|
|
|
|
|
(62,968
|
)
|
|
|
119,840
|
|
|
|
(88,515
|
)
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
52,397
|
|
|
|
$
|
(119,157
|
)
|
|
$
|
191,571
|
|
|
$
|
(67,618
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Information (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
|
|
|
()
|
|
See Note 2 to consolidated
financial statements.
|
See accompanying notes to consolidated financial statements.
F-4
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Changes in
Stockholders
Equity/Members Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Voting
|
|
|
Nonvoting
|
|
|
Unearned
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Compensation
|
|
|
Total
|
|
|
|
(in thousands of dollars)
|
|
|
Immediate Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members Equity, December 31, 2004
|
|
$
|
10,485
|
|
|
$
|
7,585
|
|
|
$
|
(3,986
|
)
|
|
$
|
14,084
|
|
Recognition of earned compensation expense related to common
units
|
|
|
|
|
|
|
|
|
|
|
3,986
|
|
|
|
3,986
|
|
Contributed capital
|
|
|
728
|
|
|
|
|
|
|
|
|
|
|
|
728
|
|
Dividends on preferred units ($0.70 per unit)
|
|
|
(44,083
|
)
|
|
|
|
|
|
|
|
|
|
|
(44,083
|
)
|
Dividends to management on common units ($0.70 per unit)
|
|
|
|
|
|
|
(8,128
|
)
|
|
|
|
|
|
|
(8,128
|
)
|
Net income
|
|
|
44,240
|
|
|
|
8,157
|
|
|
|
|
|
|
|
52,397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members Equity, June 23, 2005
|
|
$
|
11,370
|
|
|
$
|
7,614
|
|
|
$
|
|
|
|
$
|
18,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-5
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Changes in
Stockholders
Equity/Members
Equity (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management Voting
|
|
|
Note Receivable
|
|
|
|
|
|
|
Common Units
|
|
|
from Management
|
|
|
|
|
|
|
Subject to Redemption
|
|
|
Unit Holder
|
|
|
Total
|
|
|
|
Units
|
|
|
Dollars
|
|
|
Dollars
|
|
|
Dollars
|
|
|
|
(in thousands of dollars except share amounts)
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the 233 days ended December 31, 2005, and the
year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at May 13, 2005
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Issuance of 177,500 common units for cash
|
|
|
177,500
|
|
|
|
1,775
|
|
|
|
|
|
|
|
1,775
|
|
Issuance of 50,000 common units for note receivable
|
|
|
50,000
|
|
|
|
500
|
|
|
|
(500
|
)
|
|
|
|
|
Adjustment to fair value for management common units
|
|
|
|
|
|
|
3,035
|
|
|
|
|
|
|
|
3,035
|
|
Net loss allocated to management common units
|
|
|
|
|
|
|
(1,138
|
)
|
|
|
|
|
|
|
(1,138
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
227,500
|
|
|
|
4,172
|
|
|
|
(500
|
)
|
|
|
3,672
|
|
Payment of note receivable
|
|
|
|
|
|
|
|
|
|
|
150
|
|
|
|
150
|
|
Forgiveness of note receivable
|
|
|
|
|
|
|
|
|
|
|
350
|
|
|
|
350
|
|
Adjustment to fair value for management common units
|
|
|
|
|
|
|
4,240
|
|
|
|
|
|
|
|
4,240
|
|
Prorata reduction of management common units outstanding
|
|
|
(26,437
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to management on common units
|
|
|
|
|
|
|
(3,119
|
)
|
|
|
|
|
|
|
(3,119
|
)
|
Net income allocated to management common units
|
|
|
|
|
|
|
1,688
|
|
|
|
|
|
|
|
1,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
201,063
|
|
|
|
6,981
|
|
|
|
|
|
|
|
6,981
|
|
Adjustment to fair value for management common units, as
restated()
|
|
|
|
|
|
|
2,037
|
|
|
|
|
|
|
|
2,037
|
|
Net loss allocated to management common units, as
restated()
|
|
|
|
|
|
|
(362
|
)
|
|
|
|
|
|
|
(362
|
)
|
Change from partnership to corporate reporting structure
|
|
|
(201,063
|
)
|
|
|
(8,656
|
)
|
|
|
|
|
|
|
(8,656
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
F-6
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Changes in
Stockholders
Equity/Members
Equity (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Management
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvoting Override
|
|
|
Nonvoting Override
|
|
|
|
|
|
|
Voting Common Units
|
|
|
Operating Units
|
|
|
Value Units
|
|
|
Total
|
|
|
|
Units
|
|
|
Dollars
|
|
|
Units
|
|
|
Dollars
|
|
|
Units
|
|
|
Dollars
|
|
|
Dollars
|
|
|
|
(in thousands of dollars except share amounts)
|
|
|
For the 233 days ended December 31, 2005, and the
year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at May 13, 2005
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Issuance of 23,588,500 common units for cash
|
|
|
23,588,500
|
|
|
|
235,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
235,885
|
|
Issuance of 919,630 nonvested operating override units
|
|
|
|
|
|
|
|
|
|
|
919,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 1,839,265 nonvested value override units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,839,265
|
|
|
|
|
|
|
|
|
|
Recognition of share-based compensation expense related to
override units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
603
|
|
|
|
|
|
|
|
395
|
|
|
|
998
|
|
Adjustment to fair value for management common units
|
|
|
|
|
|
|
(3,035
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,035
|
)
|
Net loss allocated to common units
|
|
|
|
|
|
|
(118,019
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(118,019
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
23,588,500
|
|
|
|
114,831
|
|
|
|
919,630
|
|
|
|
603
|
|
|
|
1,839,265
|
|
|
|
395
|
|
|
|
115,829
|
|
Issuance of 2,000,000 common units for cash
|
|
|
2,000,000
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,000
|
|
Recognition of share-based compensation expense related to
override units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,160
|
|
|
|
|
|
|
|
695
|
|
|
|
1,855
|
|
Adjustment to fair value for management common units
|
|
|
|
|
|
|
(4,240
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,240
|
)
|
Prorata reduction of common units outstanding
|
|
|
(2,973,563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 72,492 nonvested operating override units
|
|
|
|
|
|
|
|
|
|
|
72,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 144,966 nonvested value override units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144,966
|
|
|
|
|
|
|
|
|
|
Distributions to common unit holders
|
|
|
|
|
|
|
(246,881
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(246,881
|
)
|
Net income allocated to common units
|
|
|
|
|
|
|
189,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
22,614,937
|
|
|
|
73,593
|
|
|
|
992,122
|
|
|
|
1,763
|
|
|
|
1,984,231
|
|
|
|
1,090
|
|
|
|
76,446
|
|
Recognition of share-based compensation expense related to
override units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,018
|
|
|
|
|
|
|
|
701
|
|
|
|
1,719
|
|
Adjustment to fair value for management common units, as
restated()
|
|
|
|
|
|
|
(2,037
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,037
|
)
|
Adjustment to fair value for minority interest
|
|
|
|
|
|
|
(1,053
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,053
|
)
|
Reversal of minority interest fair value adjustments upon
redemption of the minority interest
|
|
|
|
|
|
|
1,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,053
|
|
Net loss allocated to common units, as restated()
|
|
|
|
|
|
|
(40,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,756
|
)
|
Change from partnership to corporate reporting structure, as
restated()
|
|
|
(22,614,937
|
)
|
|
|
(30,800
|
)
|
|
|
(992,122
|
)
|
|
|
(2,781
|
)
|
|
|
(1,984,231
|
)
|
|
|
(1,791
|
)
|
|
|
(35,372
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated
financial statements.
|
See accompanying notes to consolidated financial statements.
F-7
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Changes in
Stockholders
Equity/Members
Equity (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
Paid-In
|
|
|
Retained
|
|
|
|
|
|
|
Issued
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit
|
|
|
Total
|
|
|
|
(in thousands of dollars except share amounts)
|
|
|
Balance at January 1, 2007
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Change from partnership to corporate reporting structure, as
restated()
|
|
|
62,866,720
|
|
|
|
629
|
|
|
|
43,398
|
|
|
|
|
|
|
|
44,027
|
|
Issuance of common stock in exchange for minority interest of
related party
|
|
|
247,471
|
|
|
|
2
|
|
|
|
4,700
|
|
|
|
|
|
|
|
4,702
|
|
Cash dividend declared
|
|
|
|
|
|
|
|
|
|
|
(10,600
|
)
|
|
|
|
|
|
|
(10,600
|
)
|
Public offering of common stock, net of stock issuance costs of
$39,873,655
|
|
|
22,917,300
|
|
|
|
229
|
|
|
|
395,326
|
|
|
|
|
|
|
|
395,555
|
|
Purchase of common stock by employees through share purchase
program
|
|
|
82,700
|
|
|
|
1
|
|
|
|
1,570
|
|
|
|
|
|
|
|
1,571
|
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
23,400
|
|
|
|
|
|
|
|
23,400
|
|
Issuance of common stock to employees
|
|
|
27,100
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
565
|
|
Net loss, as restated()
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,500
|
)
|
|
|
(26,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007, as restated()
|
|
|
86,141,291
|
|
|
$
|
861
|
|
|
$
|
458,359
|
|
|
$
|
(26,500
|
)
|
|
$
|
432,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
F-8
CVR ENERGY, INC.
AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days Ended
|
|
|
|
233 Days Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As restated()
|
|
|
|
(in thousands of dollars)
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
52,397
|
|
|
|
$
|
(119,157
|
)
|
|
$
|
191,571
|
|
|
$
|
(67,618
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
1,128
|
|
|
|
|
23,954
|
|
|
|
51,005
|
|
|
|
68,406
|
|
Provision for doubtful accounts
|
|
|
(190
|
)
|
|
|
|
276
|
|
|
|
100
|
|
|
|
15
|
|
Amortization of deferred financing costs
|
|
|
812
|
|
|
|
|
1,751
|
|
|
|
3,337
|
|
|
|
2,778
|
|
Loss on disposition of fixed assets
|
|
|
|
|
|
|
|
|
|
|
|
1,188
|
|
|
|
1,273
|
|
Loss on extinguishment of debt
|
|
|
8,094
|
|
|
|
|
|
|
|
|
23,360
|
|
|
|
1,258
|
|
Forgiveness of note receivable
|
|
|
|
|
|
|
|
|
|
|
|
350
|
|
|
|
|
|
Share-based compensation
|
|
|
3,986
|
|
|
|
|
1,093
|
|
|
|
16,905
|
|
|
|
44,083
|
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(210
|
)
|
Changes in assets and liabilities, net of effect of acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(11,335
|
)
|
|
|
|
(34,507
|
)
|
|
|
1,871
|
|
|
|
(16,972
|
)
|
Inventories
|
|
|
(59,045
|
)
|
|
|
|
1,895
|
|
|
|
(7,157
|
)
|
|
|
(84,980
|
)
|
Prepaid expenses and other current assets
|
|
|
(939
|
)
|
|
|
|
(6,492
|
)
|
|
|
(5,384
|
)
|
|
|
4,848
|
|
Insurance receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(105,260
|
)
|
Insurance proceeds for flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,000
|
|
Other long-term assets
|
|
|
3,036
|
|
|
|
|
(4,651
|
)
|
|
|
1,971
|
|
|
|
3,245
|
|
Accounts payable
|
|
|
16,125
|
|
|
|
|
40,656
|
|
|
|
5,005
|
|
|
|
59,110
|
|
Accrued income taxes
|
|
|
4,504
|
|
|
|
|
(136
|
)
|
|
|
(37,039
|
)
|
|
|
732
|
|
Deferred revenue
|
|
|
(9,073
|
)
|
|
|
|
9,983
|
|
|
|
(3,218
|
)
|
|
|
4,349
|
|
Other current liabilities
|
|
|
1,255
|
|
|
|
|
10,405
|
|
|
|
4,592
|
|
|
|
27,027
|
|
Payable to swap counterparty
|
|
|
|
|
|
|
|
256,722
|
|
|
|
(147,021
|
)
|
|
|
240,944
|
|
Accrued environmental liabilities
|
|
|
(1,553
|
)
|
|
|
|
(539
|
)
|
|
|
(1,614
|
)
|
|
|
(551
|
)
|
Other long-term liabilities
|
|
|
(297
|
)
|
|
|
|
(296
|
)
|
|
|
|
|
|
|
1,122
|
|
Deferred income taxes
|
|
|
3,804
|
|
|
|
|
(98,425
|
)
|
|
|
86,770
|
|
|
|
(57,684
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
12,709
|
|
|
|
|
82,532
|
|
|
|
186,592
|
|
|
|
145,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for acquisition of Immediate Predecessor, net of cash
acquired
|
|
|
|
|
|
|
|
(685,126
|
)
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(12,257
|
)
|
|
|
|
(45,172
|
)
|
|
|
(240,225
|
)
|
|
|
(268,593
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(12,257
|
)
|
|
|
|
(730,298
|
)
|
|
|
(240,225
|
)
|
|
|
(268,593
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving debt payments
|
|
|
(343
|
)
|
|
|
|
(69,286
|
)
|
|
|
(900
|
)
|
|
|
(345,800
|
)
|
Revolving debt borrowings
|
|
|
492
|
|
|
|
|
69,286
|
|
|
|
900
|
|
|
|
345,800
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
|
500,000
|
|
|
|
805,000
|
|
|
|
50,000
|
|
Principal payments on long-term debt
|
|
|
(375
|
)
|
|
|
|
(562
|
)
|
|
|
(529,438
|
)
|
|
|
(335,797
|
)
|
Payment of financing costs
|
|
|
|
|
|
|
|
(24,628
|
)
|
|
|
(9,364
|
)
|
|
|
(2,491
|
)
|
Prepayment penalty on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
(5,500
|
)
|
|
|
|
|
Payment of note receivable
|
|
|
|
|
|
|
|
|
|
|
|
150
|
|
|
|
|
|
Issuance of members equity
|
|
|
|
|
|
|
|
237,660
|
|
|
|
20,000
|
|
|
|
|
|
Net proceeds from sale of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
399,556
|
|
Distribution of members equity
|
|
|
(52,211
|
)
|
|
|
|
|
|
|
|
(250,000
|
)
|
|
|
(10,600
|
)
|
Sale of managing general partnership interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(52,437
|
)
|
|
|
|
712,470
|
|
|
|
30,848
|
|
|
|
111,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(51,985
|
)
|
|
|
|
64,704
|
|
|
|
(22,785
|
)
|
|
|
(11,410
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
52,652
|
|
|
|
|
|
|
|
|
64,704
|
|
|
|
41,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
667
|
|
|
|
$
|
64,704
|
|
|
$
|
41,919
|
|
|
$
|
30,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes, net of refunds (received)
|
|
$
|
27,040
|
|
|
|
$
|
35,593
|
|
|
$
|
70,109
|
|
|
$
|
(31,563
|
)
|
Cash paid for interest
|
|
$
|
7,287
|
|
|
|
$
|
23,578
|
|
|
$
|
51,854
|
|
|
$
|
56,886
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Step-up
in
basis in property for exchange of common stock for minority
interest, net of deferred taxes of $389
|
|
$
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
586
|
|
Accrual of construction in progress additions
|
|
$
|
|
|
|
|
$
|
|
|
|
$
|
45,991
|
|
|
$
|
(15,268
|
)
|
Contributed capital through Leiber tax savings
|
|
$
|
729
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Notes payable and capital lease obligations for insurance and
inventory
|
|
$
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
11,640
|
|
|
|
|
|
|
See Note 2 to consolidated
financial statements.
|
See accompanying notes to consolidated financial statements.
F-9
CVR ENERGY, INC.
AND SUBSIDIARIES
|
|
(1)
|
Organization and
History of the Company
|
Organization
The Company or CVR may be used to refer
to CVR Energy, Inc. and, unless the context otherwise requires,
its subsidiaries. Any references to the Company as
of a date prior to October 16, 2007 (the date of the
restructuring as further discussed in this Note) and subsequent
to June 24, 2005 are to Coffeyville Acquisition LLC (CALLC)
and its subsidiaries.
On June 24, 2005, CALLC acquired all of the outstanding
stock of Coffeyville Refining & Marketing, Inc. (CRM);
Coffeyville Nitrogen Fertilizers, Inc. (CNF); Coffeyville Crude
Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and
Coffeyville Terminal, Inc. (CT) (collectively, CRIncs). CRIncs
collectively own 100% of CL JV Holdings, LLC (CLJV) and,
directly or through CLJV, they collectively own 100% of
Coffeyville Resources, LLC (CRLLC) and its wholly owned
subsidiaries, Coffeyville Resources Refining &
Marketing, LLC (CRRM); Coffeyville Resources Nitrogen
Fertilizers, LLC (CRNF); Coffeyville Resources Crude
Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC
(CRP); and Coffeyville Resources Terminal, LLC (CRT).
The Company, through its wholly-owned subsidiaries, acts as an
independent petroleum refiner and marketer in the
mid-continental United States and a producer and marketer of
upgraded nitrogen fertilizer products in North America. The
Companys operations include two business segments: the
petroleum segment and the nitrogen fertilizer segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary,
incorporated in Delaware in September 2006, in order to effect
an initial public offering. CALLC formed Coffeyville
Refining & Marketing Holdings, Inc. (Refining Holdco)
as a wholly owned subsidiary, incorporated in Delaware in August
2007, by contributing its shares of CRM to Refining Holdco in
exchange for its shares. Refining Holdco was formed in
connection with a financing transaction in August 2007. The
initial public offering of CVR was consummated on
October 26, 2007. In conjunction with the initial public
offering, a restructuring occurred in which CVR became a direct
or indirect owner of all of the subsidiaries of CALLC.
Additionally, in connection with the initial public offering,
CALLC was split into two entities: Coffeyville Acquisition LLC
and Coffeyville Acquisition II LLC (CALLC II).
Initial Public
Offering of CVR Energy, Inc.
On October 26, 2007, CVR Energy, Inc. completed an initial
public offering of 23,000,000 shares of its common stock.
The initial public offering price was $19.00 per share.
The net proceeds to CVR from the initial public offering were
approximately $408.5 million, after deducting underwriting
discounts and commissions, but before deduction of offering
expenses. The Company also incurred approximately
$11.4 million of other costs related to the initial public
offering. The net proceeds from this offering were used to repay
$280 million of term debt under the Companys credit
facility and to repay all indebtedness under the Companys
$25 million unsecured facility and $25 million secured
facility, including related accrued interest through the date of
repayment of approximately $5.9 million. Additionally,
$50 million of net proceeds were used to repay outstanding
indebtedness under the revolving loan facility under the
Companys credit facility. In connection with the repayment
of the $25 million unsecured facility and the
$25 million secured facility, the Company recorded a
write-off of unamortized deferred financing fees of
approximately $1.3 million in the fourth quarter of 2007.
In connection with the initial public offering, CVR became the
indirect owner of the subsidiaries of CALLC and CALLC II. This
was accomplished by CVR issuing 62,866,720 shares of its
common stock to CALLC and CALLC II, its majority stockholders,
in conjunction with the mergers of two newly formed direct
subsidiaries of CVR into Refining Holdco and CNF. Concurrent
with the merger of the subsidiaries and in accordance with a
previously executed agreement, the Companys chief
executive
F-10
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
officer received 247,471 shares of CVR common stock in
exchange for shares that he owned of Refining Holdco and CNF.
The shares were fully vested and were exchanged at fair market
value.
The Company also issued 27,100 shares of common stock to
its employees on October 24, 2007 in connection with the
initial public offering. The compensation expense recorded in
the fourth quarter of 2007 was $565,000 related to shares
issued. Immediately following the completion of the offering,
there were 86,141,291 shares of common stock outstanding,
which does not include the non-vested shares issued noted below.
On October 24, 2007, 17,500 shares of non-vested stock
having a fair value of $365,000 at the date of grant were issued
to outside directors. Although ownership of the shares does not
transfer to the recipients until the shares have vested,
recipients have dividend and voting rights on these shares from
the date of grant. The fair value of each share of restricted
stock was measured based on the market price of the common stock
as of the date of grant and will be amortized over the
respective vesting periods. One-third of the restricted stock
will vest on October 24, 2008, one-third will vest on
October 24, 2009, and the final one-third will vest on
October 24, 2010. Additionally, options to purchase 10,300
common shares at an exercise price of $19.00 per share were
granted to outside directors on October 22, 2007. These
awards will vest over a three year service period. Fair value
was measured using an option-pricing model at the date of grant.
Nitrogen
Fertilizer Limited Partnership
In conjunction with the consummation of CVRs initial
public offering, CVR transferred CRNF, its nitrogen fertilizer
business, to a newly created limited partnership (Partnership)
in exchange for a managing general partner interest (managing GP
interest), a special general partner interest (special GP
interest, represented by special GP units) and a de minimis
limited partner interest (LP interest, represented by special LP
units). This transfer was not considered a business combination
as it was a transfer of assets among entities under common
control and, accordingly, balances were transferred at their
historical cost. CVR concurrently sold the managing GP interest
to an entity owned by its controlling stockholders and senior
management at fair market value. The board of directors of CVR
determined, after consultation with management, that the fair
market value of the managing general partner interest was
$10.6 million. This interest has been reflected as minority
interest in the consolidated balance sheet at December 31,
2007.
The valuation of the managing general partner interest was based
on a discounted cash flow analysis, using a discount rate
commensurate with the risk profile of the managing general
partner interest. The key assumptions underlying the analysis
were commodity price projections, which were used to determine
the Partnerships raw material costs and output revenues.
Other business expenses of the Partnership were based on
managements projections. The Partnerships cash
distributions were assumed to be flat at expected forward
fertilizer prices, with cash reserves developed in periods of
high prices and cash reserves reduced in periods of lower
prices. The Partnerships projected cash flows due to the
managing general partner under the terms of the
Partnerships partnership agreement used for the valuation
were modeled based on the structure of expectations of the
Partnerships operations, including production volumes and
operating costs, which were developed by management based on
historical operations and experience. Price projections were
based on information received from Blue, Johnson &
Associates, a leading fertilizer industry consultant in the
United States which CVR routinely uses for fertilizer market
analysis.
In conjunction with CVR Energys indirect ownership of the
special GP interest, it initially owned all of the interests in
the Partnership (other than the managing general partner
interest and the IDRs) and initially was entitled to all cash
distributed by the Partnership. The managing general partner is
not entitled to participate in Partnership distributions except
with respect to its IDRs, which entitle the managing general
partner to receive increasing percentages (up to 48%) of the
cash the Partnership
F-11
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
distributes in excess of $0.4313 per unit in a quarter. However,
the Partnership is not permitted to make any distributions with
respect to the IDRs until the aggregate Adjusted Operating
Surplus, as defined in the amended and restated partnership
agreement, generated by the Partnership during the period from
the completion of the Partnerships initial public offering
of its common units representing limited partner interests
(Partnership Offering) through December 31, 2009 has been
distributed in respect of the GP units and subordinated GP
units, which CVR Energy will indirectly hold following
completion of the Partnership Offering, and the
Partnerships common units (which will be issued in
connection with the Partnership Offering) and any other
partnership interests that are issued in the future. The
Partnership and its subsidiaries are currently guarantors under
CRLLCs credit facility.
The Partnership is operated by CVRs senior management
pursuant to a services agreement among CVR, the managing general
partner, and the Partnership. The Partnership is managed by the
managing general partner and, to the extent described below,
CVR, as special general partner. As special general partner of
the Partnership, CVR has joint management rights regarding the
appointment, termination, and compensation of the chief
executive officer and chief financial officer of the managing
general partner, has the right to designate two members of the
board of directors of the managing general partner, and has
joint management rights regarding specified major business
decisions relating to the Partnership. CVR the Partnership and
the managing general partner also entered into a number of
agreements to regulate certain business relations between the
partners.
At December 31, 2007, the Partnership had 30,333 special LP
units outstanding, representing 0.1% of the total Partnership
units outstanding, and 30,303,000 special GP interests
outstanding, representing 99.9% of the total Partnership units
outstanding. In addition, the managing general partner owned the
managing general partner interest and the IDRs. The managing
general partner contributed 1% of CRNFs interest to the
Partnership in exchange for its managing general partner
interest and the IDRs.
On February 28, 2008, the Partnership filed a registration
statement with the SEC to effect the contemplated initial public
offering of its common units representing limited partner
interests. The registration statement provided that upon
consummation of the Partnerships initial public offering,
CVR will indirectly own the Partnerships special general
partner and approximately 87% of the outstanding units of the
Partnership. There can be no assurance that any such offering
will be consummated on the terms described in the registration
statement or at all. The offering is under review by the
Securities and Exchange Commission (SEC) and as a result the
terms and resulting structure disclosed below could be
materially different.
In connection with the Partnerships initial public
offering, CRLLC will contribute all of its special LP units to
the Partnerships special general partner and all of the
Partnerships special general partner interests and special
limited partner interests will be converted into a combination
of GP and subordinated GP units. Following the initial public
offering, the Partnership will have five types of partnership
interest outstanding:
|
|
|
|
|
5,250,000 common units representing limited partner interests,
all of which the Partnership will sell in the initial public
offering;
|
|
|
|
18,750,000 GP units representing special general partner
interests, all of which will be held by the Partnerships
special general partner;
|
|
|
|
18,000,000 subordinated GP units representing special general
partner interests, all of which will be held by the
Partnerships special general partner;
|
|
|
|
incentive distribution rights representing limited partner
interests, all of which will be held by the Partnerships
managing general partner; and
|
F-12
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
a managing general partner interest, which is not entitled to
any distributions, which is held by the Partnerships
managing general partner.
|
Effective with the Partnerships initial public offering,
the partnership agreement will require that the Partnership
distribute all of its cash on hand at the end of each quarter,
less reserves established by its managing general partner,
subject to the sustainability requirement in the event the
Partnership elects to increase the quarterly distribution
amount. The amount of available cash may be greater or less than
the aggregate amount necessary to make the minimum quarterly
distribution on all common units, GP units and subordinated
units.
Subsequent to the initial public offering, the Partnership will
make minimum quarterly distributions of $0.375 per common unit
($1.50 per common unit on an annualized basis) to the extent the
Partnership has sufficient available cash. In general, cash
distributions will be made each quarter as follows:
|
|
|
|
|
First, to the holders of common units and GP units until each
common unit and GP unit has received a minimum quarterly
distribution of $0.375 plus any arrearages from prior quarters;
|
|
|
|
Second, to the holders of subordinated units, until each
subordinated unit has received a minimum quarterly distribution
of $0.375; and
|
|
|
|
Third, to all unitholders, pro rata, until each unit has
received a quarterly distribution of $0.4313.
|
If cash distributions exceed $0.4313 per unit in a quarter, the
Partnerships managing general partner, as holder of the
IDRs, will receive increasing percentages, up to 48%, of the
cash the Partnership distributes in excess of $0.4313 per unit.
However, the managing general partner will not be entitled to
receive any distributions in respect of the IDRs until the
Partnership has made cash distributions in an aggregate amount
equal to the Partnerships adjusted operating surplus
generated during the period from the closing of the initial
public offering until December 31, 2009.
During the subordination period, the subordinated units will not
be entitled to receive any distributions until the common units
and GP units have received the minimum quarterly distribution of
$0.375 per unit plus any arrearages from prior quarters. The
subordination period will end once the Partnership meets the
financial tests in the partnership agreement.
If the Partnership meets the financial tests in the partnership
agreement for any three consecutive four-quarter periods ending
on or after the first quarter whose first day begins at least
three years following the closing of the Partnership Offering,
25% of the subordinated GP units will convert into GP units on a
one-for-one basis. If the Partnership meets these financial
tests for any three consecutive four-quarter periods ending on
or after the first quarter whose first day begins at least four
years following the closing of the Partnership Offering, an
additional 25% of the subordinated GP units will convert into GP
units on a one-for-one basis. The early conversion of the second
25% of the subordinated GP units may not occur until at least
one year following the end of the last four-quarter period in
respect of which the first 25% of the subordinated GP units were
converted. If the subordinated GP units have converted into
subordinated LP units at the time the financial tests are met
they will convert into common units, rather than GP units. In
addition, the subordination period will end if the managing
general partner is removed as the managing general partner where
cause (as defined in the partnership agreement) does
not exist and no units held by the managing general partner and
its affiliates are voted in favor of that removal.
When the subordination period ends, all subordinated units will
convert into GP units or common units on a one-for-one basis,
and the common units and GP units will no longer be entitled to
arrearages.
F-13
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The partnership agreement authorizes the Partnership to issue an
unlimited number of additional units and rights to buy units for
the consideration and on the terms and conditions determined by
the managing general partner without the approval of the
unitholders.
The Partnership will distribute all cash received by it or its
subsidiaries in respect of accounts receivable existing as of
the closing of the initial public offering exclusively to its
special general partner.
The managing general partner, together with the special general
partner, manages and operates the Partnership. Common
unitholders will only have limited voting rights on matters
affecting the Partnership. In addition, common unitholders will
have no right to elect either of the general partners or the
managing general partners directors on an annual or other
continuing basis.
If at any time the managing general partner and its affiliates
own more than 80% of the common units, the managing general
partner will have the right, but not the obligation, to purchase
all of the remaining common units at a purchase price equal to
the greater of (x) the average of the daily closing price
of the common units over the 20 trading days preceding the date
three days before notice of exercise of the call right is first
mailed and (y) the highest
per-unit
price paid by the managing general partner or any of its
affiliates for common units during the
90-day
period preceding the date such notice is first mailed.
Successor and
Immediate Predecessor
Successor refers collectively to both CVR Energy, Inc. and
CALLC. CALLC was formed as a Delaware limited liability company
on May 13, 2005. On June 24, 2005, CALLC acquired all
of the outstanding stock of CRIncs from Coffeyville Group
Holdings, LLC (Immediate Predecessor) (the Subsequent
Acquisition). As a result of this transaction, CRIncs ownership
increased to 100% of CLJV, a Delaware limited liability company
formed on September 27, 2004. CRIncs directly and
indirectly, through CLJV, collectively own 100% of CRLLC and its
wholly owned subsidiaries, CRRM; CRNF; CRCT; CRP; and CRT.
CALLC had no financial statement activity during the period from
May 13, 2005 to June 24, 2005, with the exception of
certain crude oil, heating oil, and gasoline option agreements
entered into with a related party (see Notes 16 and
17) as of May 16, 2005. These agreements expired
unexercised on June 16, 2005 and resulted in an expense of
$25,000,000 reported in the accompanying consolidated statements
of operations as gain (loss) on derivatives for the
233 days ended December 31, 2005.
Immediate Predecessor was a Delaware limited liability company
formed in October 2003. There was no financial statement
activity until March 3, 2004, when Immediate Predecessor,
acting through wholly owned subsidiaries, acquired the assets of
the former Farmland Industries, Inc. (Farmland) Petroleum
Division and one facility located in Coffeyville, Kansas within
Farmlands eight-plant Nitrogen Fertilizer Manufacturing
and Marketing Division (collectively, Original Predecessor) (the
Initial Acquisition). As of March 3, 2004, Immediate
Predecessor owned 100% of CRIncs, and CRIncs owned 100% of CRLLC
and its wholly owned subsidiaries, CRRM, CRNF, CRCT, CRP, and
CRT. Farmland was a farm supply cooperative and a processing and
marketing cooperative.
Since the assets and liabilities of Successor and Immediate
Predecessor (collectively, CVR) were each presented on a new
basis of accounting, the financial information for Successor and
Immediate Predecessor, is not comparable.
On October 8, 2004, Immediate Predecessor, acting through
its wholly owned subsidiaries, CRM and CNF, contributed 68.7% of
its membership in CRLLC to CLJV, in exchange for a controlling
interest in CLJV. Concurrently, The Leiber Group, Inc., a
company whose majority stockholder was Pegasus Partners II,
L.P., the Immediate Predecessors principal stockholder,
contributed to CLJV its
F-14
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
interest in the Judith Leiber business, a designer handbag
business, in exchange for a minority interest in CLJV. The
Judith Leiber business was at the time owned through Leiber
Holdings, LLC (LH), a Delaware limited liability company wholly
owned at the time by CLJV. Based on the relative values of the
properties at the time of contribution to CLJV, CRM and CNF
collectively, were entitled to 80.5% of CLJVs net profits
and net losses. Under the terms of CRLLCs credit
agreement, CRLLC was permitted to make tax distributions to its
members, including CLJV, in amounts equal to the tax liability
that would be incurred by CRLLC if its net income were subject
to corporate-level income tax. From the tax distributions CLJV
received from CRLLC as of December 31, 2004 and
June 23, 2005, CLJV contributed $1,600,000 and $4,050,000,
respectively, to LH which is presented as tax expense in the
respective periods in the accompanying consolidated statements
of operations for the reasons discussed below.
On June 23, 2005, as part of the stock purchase agreement,
LH completed a merger with Leiber Merger, LLC, a wholly owned
subsidiary of The Leiber Group, Inc. As a result of the merger,
the surviving entity was LH. Under the terms of the agreement,
CLJV forfeited all of its ownership in LH to The Leiber Group,
Inc in exchange for LHs interest in CLJV. The result of
this transaction was to effectively redistribute the contributed
businesses back to The Leiber Group, Inc.
The operations of LH and its subsidiaries (collectively, Leiber)
have not been included in the accompanying consolidated
financial statements of the Predecessor because Leibers
operations were unrelated to, and are not part of, the ongoing
operations of CVR. CLJVs management was not the same as
the Immediate Predecessors, the Successors, or
CVRs, there were no intercompany transactions between CLJV
and the Immediate Predecessor, the Successor, or CVR, aside from
the contributions, and the Immediate Predecessor only
participated in the joint venture for a short period of time.
The tax benefits received from LH, as a result of losses
incurred by LH, have been reflected as capital contributions in
the accompanying consolidated financial statements of the
Immediate Predecessor.
F-15
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Successor
Acquisition
On May 15, 2005, Successor and Immediate Predecessor
entered into an agreement whereby Successor acquired 100% of the
outstanding stock of CRIncs with an effective date of
June 24, 2005 for $673,273,000, including the assumption of
$353,085,000 of liabilities. Successor also paid transaction
costs of $12,519,000, which consisted of legal, accounting, and
advisory fees of $5,783,000 paid to various parties, and
transaction fees of $6,000,000 and $736,000 in expenses related
to the acquisition paid to institutional investors (see
Note 17). Successors primary reason for the purchase
was the belief that long-term fundamentals for the refining
industry were strengthening and the capital requirement was
within its desired investment range. The cost of the Subsequent
Acquisition was financed through long-term borrowings of
approximately $500 million, short-term borrowings of
approximately $12.6 million, and the issuance of common
units for approximately $227.7 million. The allocation of
the purchase price at June 24, 2005, the date of the
Subsequent Acquisition, is as follows:
|
|
|
|
|
Assets acquired
|
|
|
|
|
Cash
|
|
$
|
667,000
|
|
Accounts receivable
|
|
|
37,329,000
|
|
Inventories
|
|
|
156,171,000
|
|
Prepaid expenses and other current assets
|
|
|
4,865,000
|
|
Intangibles, contractual agreements
|
|
|
1,322,000
|
|
Goodwill
|
|
|
83,775,000
|
|
Other long-term assets
|
|
|
3,838,000
|
|
Property, plant, and equipment
|
|
|
750,910,000
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
1,038,877,000
|
|
|
|
|
|
|
Liabilities assumed
|
|
|
|
|
Accounts payable
|
|
$
|
47,259,000
|
|
Other current liabilities
|
|
|
16,017,000
|
|
Current income taxes
|
|
|
5,076,000
|
|
Deferred income taxes
|
|
|
276,889,000
|
|
Other long-term liabilities
|
|
|
7,844,000
|
|
|
|
|
|
|
Total liabilities assumed
|
|
$
|
353,085,000
|
|
|
|
|
|
|
Cash paid for acquisition of Immediate Predecessor
|
|
$
|
685,792,000
|
|
|
|
|
|
|
|
|
(2)
|
Restatement of
Financial Statements
|
(A) On April 23, 2008, the Audit Committee of the
Board of Directors and management of the Company concluded that
the Companys previously issued consolidated financial
statements for the year ended December 31, 2007 and the
related quarter ended September 30, 2007 contained errors.
The Company arrived at this conclusion during the course of its
closing process and review for the quarter ended March 31,
2008. The restatement principally relates to errors in the
calculation of the cost of crude oil purchased by the Company
and associated financial transactions.
For the year ended December 31, 2007, net loss increased by
$10.8 million, from $56.8 million to
$67.6 million. This increase in net loss is the result of
an increase in cost of product sold (exclusive of depreciation
and amortization) of $17.7 million, with an associated
increase in income tax benefit of $6.9 million.
Due to the restatement, inventories for the year ended
December 31, 2007 increased by $5.4 million and
accounts payable increased by $23.1 million. Income tax
receivable increased by $6.1 million and current deferred
income tax asset increased by $0.8 million.
F-16
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The effect of the above adjustments on the consolidated
financial statements is set forth in the tables in 2(B) below.
The restatement had no effect on net cash flows from operating,
investing or financing activities as shown in the Consolidated
Statements of Cash Flows. The restatement did not have any
impact on the Companys covenant compliance under its debt
facilities or its cash position as of December 31, 2007.
(B) Notes 5, 11, 13, 15, 17, 18, 19 and 20 have been
restated to reflect the adjustments described above.
F-17
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The following is a summary of the impact of the restatement
described in Note 2(A) on the Companys Consolidated
Balance Sheet as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustment
|
|
|
Restated
|
|
|
Assets
|
Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
30,509
|
|
|
$
|
|
|
|
$
|
30,509
|
|
Accounts receivable, net of allowance for doubtful accounts of
$375 and $391, respectively
|
|
|
86,546
|
|
|
|
|
|
|
|
86,546
|
|
Inventories
|
|
|
249,243
|
|
|
|
5,412
|
|
|
|
254,655
|
|
Prepaid expenses and other current assets
|
|
|
14,186
|
|
|
|
|
|
|
|
14,186
|
|
Insurance receivable
|
|
|
73,860
|
|
|
|
|
|
|
|
73,860
|
|
Income tax receivable
|
|
|
25,273
|
|
|
|
6,094
|
|
|
|
31,367
|
|
Deferred income taxes
|
|
|
78,265
|
|
|
|
782
|
|
|
|
79,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
557,882
|
|
|
|
12,288
|
|
|
|
570,170
|
|
Property, plant, and equipment, net of accumulated depreciation
|
|
|
1,192,174
|
|
|
|
|
|
|
|
1,192,174
|
|
Intangible assets, net
|
|
|
473
|
|
|
|
|
|
|
|
473
|
|
Goodwill
|
|
|
83,775
|
|
|
|
|
|
|
|
83,775
|
|
Deferred financing costs, net
|
|
|
7,515
|
|
|
|
|
|
|
|
7,515
|
|
Insurance receivable
|
|
|
11,400
|
|
|
|
|
|
|
|
11,400
|
|
Other long-term assets
|
|
|
2,849
|
|
|
|
|
|
|
|
2,849
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,856,068
|
|
|
$
|
12,288
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Equity
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
4,874
|
|
|
|
|
|
|
|
4,874
|
|
Note payable and capital lease obligations
|
|
|
11,640
|
|
|
|
|
|
|
|
11,640
|
|
Payable to swap counterparty
|
|
|
262,415
|
|
|
|
|
|
|
|
262,415
|
|
Accounts payable
|
|
|
159,142
|
|
|
|
23,083
|
|
|
|
182,225
|
|
Personnel accruals
|
|
|
36,659
|
|
|
|
|
|
|
|
36,659
|
|
Accrued taxes other than income taxes
|
|
|
14,732
|
|
|
|
|
|
|
|
14,732
|
|
Deferred revenue
|
|
|
13,161
|
|
|
|
|
|
|
|
13,161
|
|
Other current liabilities
|
|
|
33,820
|
|
|
|
|
|
|
|
33,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
536,443
|
|
|
|
23,083
|
|
|
|
559,526
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
484,328
|
|
|
|
|
|
|
|
484,328
|
|
Accrued environmental liabilities
|
|
|
4,844
|
|
|
|
|
|
|
|
4,844
|
|
Deferred income taxes
|
|
|
286,986
|
|
|
|
|
|
|
|
286,986
|
|
Other long-term liabilities
|
|
|
1,122
|
|
|
|
|
|
|
|
1,122
|
|
Payable to swap counterparty
|
|
|
88,230
|
|
|
|
|
|
|
|
88,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
865,510
|
|
|
|
|
|
|
|
865,510
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in subsidiaries
|
|
|
10,600
|
|
|
|
|
|
|
|
10,600
|
|
Management voting common units subject to redemption,
201,063 units issued and outstanding in 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity/members equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Voting common units, 22,614,937 units issued and
outstanding in 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Management nonvoting override units, 2,976,353 units issued
and
outstanding in 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock $0.01 par value per share,
350,000,000 shares authorized; 86,141,291 shares
issued and outstanding
|
|
|
861
|
|
|
|
|
|
|
|
861
|
|
Additional
paid-in-capital
|
|
|
460,551
|
|
|
|
(2,192
|
)
|
|
|
458,359
|
|
Retained deficit
|
|
|
(17,897
|
)
|
|
|
(8,603
|
)
|
|
|
(26,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity/members equity
|
|
|
443,515
|
|
|
|
(10,795
|
)
|
|
|
432,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity/members
equity
|
|
$
|
1,856,068
|
|
|
$
|
12,288
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-18
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The following is a summary of the impact of the restatement
described in Note 2(A) above on the Companys
Consolidated Statements of Operations for the year ended
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustment
|
|
|
As Restated
|
|
|
Net sales
|
|
$
|
2,966,865
|
|
|
$
|
|
|
|
$
|
2,966,865
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
2,291,069
|
|
|
|
17,671
|
|
|
|
2,308,740
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
276,138
|
|
|
|
|
|
|
|
276,138
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
93,122
|
|
|
|
|
|
|
|
93,122
|
|
Net costs associated with flood
|
|
|
41,523
|
|
|
|
|
|
|
|
41,523
|
|
Depreciation and amortization
|
|
|
60,779
|
|
|
|
|
|
|
|
60,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
2,762,631
|
|
|
|
17,671
|
|
|
|
2,780,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
204,234
|
|
|
|
(17,671
|
)
|
|
|
186,563
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(61,126
|
)
|
|
|
|
|
|
|
(61,126
|
)
|
Interest income
|
|
|
1,100
|
|
|
|
|
|
|
|
1,100
|
|
Gain (loss) on derivatives
|
|
|
(281,978
|
)
|
|
|
|
|
|
|
(281,978
|
)
|
Loss on extinguishment of debt
|
|
|
(1,258
|
)
|
|
|
|
|
|
|
(1,258
|
)
|
Other income (expense)
|
|
|
356
|
|
|
|
|
|
|
|
356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(342,906
|
)
|
|
|
|
|
|
|
(342,906
|
)
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
|
(138,672
|
)
|
|
|
(17,671
|
)
|
|
|
(156,343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
|
(81,639
|
)
|
|
|
(6,876
|
)
|
|
|
(88,515
|
)
|
Minority interest in loss of subsidiaries
|
|
|
210
|
|
|
|
|
|
|
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(56,823
|
)
|
|
$
|
(10,795
|
)
|
|
$
|
(67,618
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Information (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.66
|
)
|
|
$
|
(0.12
|
)
|
|
$
|
(0.78
|
)
|
Diluted
|
|
$
|
(0.66
|
)
|
|
$
|
(0.12
|
)
|
|
$
|
(0.78
|
)
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
Diluted
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
(3)
|
Summary of
Significant Accounting Policies
|
Principles of
Consolidation
The accompanying CVR consolidated financial statements include
the accounts of CVR Energy, Inc. and its majority-owned direct
and indirect subsidiaries. The ownership interest of minority
investors in its subsidiaries are recorded as minority interest.
All intercompany accounts and transactions have been eliminated
in consolidation.
F-19
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Cash and Cash
Equivalents
For purposes of the consolidated statements of cash flows, CVR
considers all highly liquid debt instruments with original
maturities of three months or less to be cash equivalents. In
connection with CVRs initial public offering,
$4.2 million of deferred offering costs in 2007 were
presented in operating activities in the interim financial
statements. Such amounts have now been reflected as financing
activities for the 2007 period in the Consolidated Statements of
Cash Flows. The impact on prior financial statements of this
revision is not considered material.
Accounts
Receivable
CVR grants credit to its customers. Credit is extended based on
an evaluation of a customers financial condition;
generally, collateral is not required. Accounts receivable are
due on negotiated terms and are stated at amounts due from
customers, net of an allowance for doubtful accounts. Accounts
outstanding longer than their contractual payment terms are
considered past due. CVR determines its allowance for doubtful
accounts by considering a number of factors, including the
length of time trade accounts are past due, the customers
ability to pay its obligations to CVR, and the condition of the
general economy and the industry as a whole. CVR writes off
accounts receivable when they become uncollectible, and payments
subsequently received on such receivables are credited to the
allowance for doubtful accounts. At December 31, 2006 and
December 31, 2007, two customers individually represented
greater than 10% and collectively represented 29% and 29%,
respectively, of the total accounts receivable balance. The
largest concentration of credit for any one customer at
December 31, 2006 and December 31, 2007 was 16% and
15%, respectively, of the accounts receivable balance.
Inventories
Inventories consist primarily of crude oil, blending stock and
components, work in progress, fertilizer products, and refined
fuels and by-products. Inventories are valued at the lower of
the
first-in,
first-out (FIFO) cost, or market for fertilizer products,
refined fuels and by-products for all periods presented.
Refinery unfinished and finished products inventory values were
determined using the ability-to-bare process, whereby raw
materials and production costs are allocated to
work-in-process
and finished products based on their relative fair values. Other
inventories, including other raw materials, spare parts, and
supplies, are valued at the lower of moving average cost, which
approximates FIFO, or market. The cost of inventories includes
inbound freight costs.
Prepaid
Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments
for crude oil deliveries to the refinery for which title had not
transferred, non-trade accounts receivables, current portions of
prepaid insurance and deferred financing costs, and other
general current assets.
Property,
Plant, and Equipment
Additions to property, plant and equipment, including
capitalized interest and certain costs allocable to construction
and property purchases, are recorded at cost. Capitalized
interest is added to any capital project over $1,000,000 in cost
which is expected to take more than six months to complete.
Depreciation is computed using principally the straight-line
method over the estimated
F-20
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
useful lives of the various classes of depreciable assets. The
lives used in computing depreciation for such assets are as
follows:
|
|
|
|
|
Range of Useful
|
Asset
|
|
Lives, in Years
|
|
Improvements to land
|
|
15 to 20
|
Buildings
|
|
20 to 30
|
Machinery and equipment
|
|
5 to 30
|
Automotive equipment
|
|
5
|
Furniture and fixtures
|
|
3 to 7
|
Our leasehold improvements are depreciated on the straight-line
method over the shorter of the contractual lease term or the
estimated useful life. Expenditures for routine maintenance and
repair costs are expenses when incurred. Such expenses are
reported in direct operating expenses (exclusive of depreciation
and amortization) in the Companys consolidated statements
of operations.
Goodwill and
Intangible Assets
Goodwill represents the excess of the cost of an acquired entity
over the fair value of the assets acquired less liabilities
assumed. Intangible assets are assets that lack physical
substance (excluding financial assets). Goodwill acquired in a
business combination and intangible assets with indefinite
useful lives are not amortized, and intangible assets with
finite useful lives are amortized. Goodwill and intangible
assets not subject to amortization are tested for impairment
annually or more frequently if events or changes in
circumstances indicate the asset might be impaired. CVR uses
November 1 of each year as its annual valuation date for the
impairment test. The annual review of impairment is performed by
comparing the carrying value of the applicable reporting unit to
its estimated fair value, using a combination of the discounted
cash flow analysis and market approach. Our reporting units are
defined as operating segments due to each operating segment
containing only one component. As such all goodwill impairment
testing is done at each operating segment.
Deferred
Financing Costs
Deferred financing costs related to the term debt are amortized
to interest expense and other financing costs using the
effective-interest method over the life of the term debt.
Deferred financing costs related to the revolving loan facility
and the funded letters of credit facility are amortized to
interest expense and other financing costs using the
straight-line method through the termination date of each credit
facility.
Planned Major
Maintenance Costs
The direct-expense method of accounting is used for planned
major maintenance activities. Maintenance costs are recognized
as expense when maintenance services are performed. During the
year ended December 31, 2006, the Coffeyville nitrogen
plant completed a major scheduled turnaround. Costs of
approximately $2,570,000 associated with the turnaround are
included in direct operating expenses (exclusive of depreciation
and amortization). The Coffeyville refinery completed a major
scheduled turnaround in 2007. Costs of approximately $3,984,000
and $76,393,000, associated with the 2007 turnaround, were
included in direct operating expenses (exclusive of depreciation
and amortization) for the year ended December 31, 2006 and
December 31, 2007, respectively.
Planned major maintenance activities for the nitrogen plant
generally occur every two years. The required frequency of the
maintenance varies by unit, for the refinery, but generally is
every four years.
F-21
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Cost
Classifications
Cost of product sold (exclusive of depreciation and
amortization) includes cost of crude oil, other feedstocks,
blendstocks, pet coke expense and freight and distribution
expenses. Cost of product sold excludes depreciation and
amortization of approximately $150,000, $1,061,000, $2,148,000,
and $2,390,000 for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007, respectively.
Direct operating expenses (exclusive of depreciation and
amortization) includes direct costs of labor, maintenance and
services, energy and utility costs, environmental compliance
costs as well as chemicals and catalysts and other direct
operating expenses. Direct operating expenses exclude
depreciation and amortization of approximately $907,000,
$22,706,000, $47,714,000, and $57,367,000 for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007,
respectively. Direct operating expenses also exclude
depreciation of $7,627,000 for the year ended December 31,
2007 that is included in Net Costs Associated with
Flood on the consolidated statement of operations as a
result of the assets being idle due to the flood.
Selling, general and administrative expenses (exclusive of
depreciation and amortization) consist primarily of legal
expenses, treasury, accounting, marketing, human resources and
maintaining the corporate offices in Texas and Kansas. Selling,
general and administrative expenses excludes depreciation and
amortization of approximately $71,000, $187,000, $1,143,000, and
$1,022,000 for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007, respectively.
Income
Taxes
CVR accounts for income taxes under the provision of Statement
Financial Accounting Standards (SFAS) No. 109,
Accounting for Income Taxes
. SFAS 109 requires the
asset and liability approach for accounting for income taxes.
Under this method, deferred tax assets and liabilities are
recognized for the anticipated future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred amounts are measured using
enacted tax rates expected to apply to taxable income in the
year those temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that
includes the enactment date.
As discussed in Note 11 (Income Taxes), CVR
adopted Financial Accounting Standards Board (FASB)
Interpretation No. 48,
Accounting for Uncertainty in
Income Taxes an Interpretation of FASB No. 109
(FIN 48) effective January 1, 2007.
Consolidation
of Variable Interest Entities
In accordance with FASB Interpretation No. 46R,
Consolidation of Variable Interest Entities
,
(FIN 46R), management has reviewed the terms associated
with its interests in the Partnership based upon the partnership
agreement. Management has determined that the Partnership is a
variable interest entity (VIE) and as such has evaluated the
criteria under FIN 46R to determine that CVR is the primary
beneficiary of the Partnership. FIN 46R requires the
primary beneficiary of a variable interest entitys
activities to consolidate the VIE. FIN 46R defines a
variable interest entity as an entity in which the equity
investors do not have substantive voting rights and where there
is not sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support. As
the primary beneficiary, CVR absorbs the majority of the
expected losses
and/or
receives a majority of the expected residual returns of the
VIEs activities.
F-22
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Impairment of
Long-Lived Assets
CVR accounts for long-lived assets in accordance with
SFAS No. 144,
Accounting for the Impairment or
Disposal of Long-Lived Assets
. In accordance with
SFAS 144, CVR reviews long-lived assets (excluding
goodwill, intangible assets with indefinite lives, and deferred
tax assets) for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. Recoverability of assets to be held and used
is measured by a comparison of the carrying amount of an asset
to estimated undiscounted future net cash flows expected to be
generated by the asset. If the carrying amount of an asset
exceeds its estimated undiscounted future net cash flows, an
impairment charge is recognized for the amount by which the
carrying amount of the assets exceeds their fair value. Assets
to be disposed of are reported at the lower of their carrying
value or fair value less cost to sell. No impairment charges
were recognized for any of the periods presented.
Revenue
Recognition
Revenues for products sold are recorded upon delivery of the
products to customers, which is the point at which title is
transferred, the customer has the assumed risk of loss, and when
payment has been received or collection is reasonably assumed.
Deferred revenue represents customer prepayments under contracts
to guarantee a price and supply of nitrogen fertilizer in
quantities expected to be delivered in the next 12 months
in the normal course of business. Excise and other taxes
collected from customers and remitted to governmental
authorities are not included in reported revenues.
Shipping
Costs
Pass-through finished goods delivery costs reimbursed by
customers are reported in net sales, while an offsetting expense
is included in cost of product sold (exclusive of depreciation
and amortization).
Derivative
Instruments and Fair Value of Financial
Instruments
CVR uses futures contracts, options, and forward swap contracts
primarily to reduce the exposure to changes in crude oil prices,
finished goods product prices and interest rates and to provide
economic hedges of inventory positions. These derivative
instruments have not been designated as hedges for accounting
purposes. Accordingly, these instruments are recorded in the
consolidated balance sheets at fair value, and each
periods gain or loss is recorded as a component of gain
(loss) on derivatives in accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities.
Financial instruments consisting of cash and cash equivalents,
accounts receivable, and accounts payable are carried at cost,
which approximates fair value, as a result of the short-term
nature of the instruments. The carrying value of long-term and
revolving debt approximates fair value as a result of the
floating interest rates assigned to those financial instruments.
Share-Based
Compensation
CVR, CALLC, CALLC II and CALLC III account for share-based
compensation in accordance with SFAS No. 123(R),
Share-Based Payments
and
EITF 00-12
Issue
No. 00-12,
Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee
(EITF 00-12).
CVR has been allocated non-cash share-based compensations
expense from CALLC, CALLC II and CALLC III.
In accordance with SFAS 123(R), CVR, CALLC, CALLC II and
CALLC III apply a fair-value based measurement method in
accounting for share-based compensation. In accordance with
F-23
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
EITF 00-12,
CVR recognizes the costs of the share-based compensation
incurred by CALLC, CALLC II and CALLC III on its behalf,
primarily in selling, general, and administrative expenses
(exclusive of depreciation and amortization), and a
corresponding capital contribution, as the costs are incurred on
its behalf, following the guidance in EITF Issue
No. 96-18,
Accounting for Equity Investments That Are Issued to Other
Than Employees for Acquiring, or in Conjunction with Selling
Goods or Services
, which requires variable accounting in the
circumstances.
Non-vested shares, when granted, are valued at the closing
market price of CVRs common stock on the date of issuance
and amortized to compensation expense on a straight-line basis
over the vesting period of the stock. The fair value of the
stock options is estimated on the date of grant using the
Black Scholes option pricing model.
As of December 31, 2007, there had been 17,500 shares
of non-vested common stock awarded. Although ownership of the
shares does not transfer to the recipients until the shares have
vested, recipients have voting and non-forfeitable dividend
rights on these shares from the date of grant. See Note 4,
Members Equity and Share-Based Compensation.
Environmental
Matters
Liabilities related to future remediation costs of past
environmental contamination of properties are recognized when
the related costs are considered probable and can be reasonably
estimated. Estimates of these costs are based upon currently
available facts, internal and third-party assessments of
contamination, available remediation technology, site-specific
costs, and currently enacted laws and regulations. In reporting
environmental liabilities, no offset is made for potential
recoveries. Loss contingency accruals, including those for
environmental remediation, are subject to revision as further
information develops or circumstances change and such accruals
can take into account the legal liability of other parties.
Environmental expenditures are capitalized at the time of the
expenditure when such costs provide future economic benefits.
Use of
Estimates
The consolidated financial statements have been prepared in
conformity with U.S. generally accepted accounting
principles, using managements best estimates and judgments
where appropriate. These estimates and judgments affect the
reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ
materially from these estimates and judgments.
New Accounting
Pronouncements
In September 2006, the FASB issued FAS No. 157,
Fair Value Measurements
, which establishes a framework
for measuring fair value in GAAP and expands disclosures about
fair value measurements. FAS 157 states that fair
value is the price that would be received to sell the
asset or paid to transfer the liability (an exit price), not the
price that would be paid to acquire the asset or received to
assume the liability (an entry price). The statement is
effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods
within those fiscal years. The Company is currently evaluating
the effect that this statement will have on its financial
statements.
In February 2007, the FASB issued FAS No. 159,
The
Fair Value Option for Financial Assets and Financial Liabilities
(FAS 159). Under this standard, an entity is required
to provide additional information that will assist investors and
other users of financial information to more easily understand
the effect of the companys choice to use fair value on its
earnings. Further, the entity is required to display the fair
value of those assets and liabilities for which the company has
chosen to use fair value on the face of the balance sheet. This
standard does not eliminate the disclosure requirements about
F-24
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
fair value measurements included in FAS 157 and
FAS No. 107,
Disclosures about Fair Value of
Financial Instruments
. FAS 159 is effective for fiscal
years beginning after November 15, 2007, and early adoption
is permitted as of January 1, 2007, provided that the
entity makes that choice in the first quarter of 2007 and also
elects to apply the provisions of FAS 157. We are currently
evaluating the potential impact that FAS 159 will have on
our financial condition, results of operations and cash flows.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
. This statement defines the
acquirer as the entity that obtains control of one or more
businesses in the business combination, establishes the
acquisition date as the date that the acquirer achieves control
and requires the acquirer to recognize the assets acquired,
liabilities assumed and any noncontrolling interest at their
fair values as of the acquisition date. This statement also
requires that acquisition-related costs of the acquirer be
recognized separately from the business combination and will
generally be expensed as incurred. CVR will be required to adopt
this statement as of January 1, 2009. The impact of
adopting SFAS 141R will be limited to any future business
combinations for which the acquisition date is on or after
January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting standards
for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary is an ownership interest
in the consolidated entity that should be reported as equity in
the consolidated financial statements. SFAS 160 requires
retroactive adoption of the presentation and disclosure
requirements for existing minority interests. All other
requirements of SFAS 160 must be applied prospectively.
SFAS 160 is effective for us beginning January 1,
2009. The Company is currently evaluating the potential impact
of the adoption of SFAS 160 on its consolidated financial
statements.
|
|
(4)
|
Members
Equity and Share Based Compensation
|
Management of Immediate Predecessor was issued 11,152,941
nonvoting restricted common units for recourse promissory notes
aggregating $63,000. Concurrent with the Acquisition at
June 23, 2005, as described in Note 1, all of the
restricted common units of management were fully vested.
Immediate Predecessor recognized $3,986,000 in compensation
expense for the
174-day
period ended June 23, 2005, related to earned compensation.
On June 23, 2005, immediately prior to the Acquisition (see
Note 1), the Immediate Predecessor used available cash
balances to distribute a $52,211,000 dividend to the preferred
and common unit holders pro rata according to their ownership
percentages, as determined by the aggregate of the common and
preferred units.
Successor issued 22,766,000 voting common units at $10 par
value for cash to finance the Acquisition, as described in
Note 1. An additional 50,000 voting common units at
$10 par value were issued to a member of management for an
unsecured recourse promissory note that accrued interest at 7%
and required annual principal and interest payments through
December 2009. The unpaid balance of the unsecured recourse
promissory note and all unpaid interest was forgiven
September 25, 2006 (see Note 17).
As required by the term loan agreements to fund certain capital
projects, on September 14, 2005 an additional $10,000,000
capital contribution was received in return for 1,000,000 voting
common units and on May 23, 2006 an additional $20,000,000
capital contribution was received in return for 2,000,000 at
$10 par value (Delayed Draw Capital).
Common units held by management contained put rights held by
management and call rights held by CALLC exercisable at fair
value in the event the management member became inactive.
Accordingly, in accordance with EITF Topic
No. D-98,
Classification and Measurement of Redeemable
F-25
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Securities
, common units held by management were
initially recorded at fair value at the date of issuance and
were classified in temporary equity as Management Voting Common
Units Subject to Redemption (Capital Subject to Redemption) in
the accompanying consolidated balance sheets. The put rights and
call rights were eliminated in October 2007.
On November 30, 2006, an amendment to the Second Amended
and Restated Limited Liability Company Agreement of Coffeyville
Acquisition LLC was approved with a pro rata reduction among all
holders of common units in order to effect a total reduction of
the number of outstanding Common Units. This amendment reduced
the number of outstanding Common Units by 11.62%. Because cash
unit holders value and ownership interest before and after
the reallocation is unchanged and since no transfer of value
occurred among the common unit holders, this pro rata reduction
had no accounting consequence. At December 31, 2006,
management held 201,063 of the 22,816,000 voting common units.
On December 28, 2006, successor refinanced its existing
long-term debt with $775 million term loan and used the
proceeds of the borrowings to repay the outstanding borrowings
under its previous first and second lien credit facilities, pay
related fees and expenses and pay a distribution of
$250 million to its common unit holders at
December 31, 2006.
The put rights with respect to managements common units,
provide that following their termination of employment, they
have the right to sell all (but not less than all) of their
common units to Coffeyville Acquisition LLC at their Fair
Market Value (as that term is defined in the LLC
Agreement) if they were terminated without Cause, or
as a result of death, Disability or resignation with
Good Reason (each as defined in the LLC Agreement)
or due to Retirement (as that term is defined in the
LLC Agreement). Coffeyville Acquisition LLC has call rights with
respect to the executives common units, so that following
the executives termination of employment, Coffeyville
Acquisition LLC has the right to purchase the common units at
their Fair Market Value if the executive was terminated without
Cause, or as a result of the executives death, Disability
or resignation with Good Reason or due to Retirement. The call
price will be the lesser of the common units Fair Market
Value or Carrying Value (which means the capital contribution,
if any, made by the executive in respect of such interest less
the amount of distributions made in respect of such interest) if
the executive is terminated for Cause or he resigns without Good
Reason. For any other termination of employment, the call price
will be at the Fair Market Value or Carrying Value of such
common units, in the sole discretion of Coffeyville Acquisition
LLCs board of directors. No put or call rights apply to
override units following the executives termination of
employment unless Coffeyville Acquisition LLs board of
directors (or the compensation committee thereof) determines in
its discretion that put and call rights will apply.
CVR accounts for changes in redemption value of management
common units in the period the changes occur and adjusts the
carrying value of the Management Voting Common Units Subject to
Redemption to equal the redemption value at the end of each
reporting period with an equal and offsetting adjustment to
Members Equity. None of the Management Voting Common Units
Subject to Redemption were redeemable at December 31, 2005
or December 31, 2006.
At December 31, 2005 the Management Voting Common Units
Subject to Redemption were revalued through an independent
appraisal process, and the value was determined to be $18.34 per
unit. Accordingly, the carrying value of the Management Voting
Common Units Subject to Redemption increased by $3,035,000 for
the
233-day
period ended December 31, 2005 with an equal and offsetting
decrease to Members Equity.
At December 31, 2006, the Management Voting Common Units
Subject to Redemption were revalued through an independent
appraisal process, and the value was determined to be $34.72 per
unit. The appraisal utilized a discounted cash flow (DCF)
method, a variation of the income approach, and the guideline
public company method, a variation of the market approach, to
determine the fair
F-26
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
value. The guideline public company method utilized a weighting
of market multiples from publicly-traded petroleum refiners and
fertilizer manufactures that are comparable to the Company. The
recognition of the value of $34.72 per unit increased the
carrying value of the Management Voting Common Units Subject to
Redemption by $4,240,000 for the year ended December 31,
2006 with an equal and offsetting decrease to Members
Equity. This increase was the result of higher forward market
price assumptions, which were consistent with what was observed
in the market during the period, in the refining business
resulting in increased free cash flow projections utilized in
the DCF method. The market multiples for the public-traded
comparable companies also increased from December 31, 2005,
resulting in increased value of the units.
Concurrent with the Subsequent Acquisition, Successor issued
nonvoting override operating units to certain management members
who hold common units. There were no required capital
contributions for the override operating units.
Upon completion of the initial public offering on
October 26, 2007, members equity, Management Voting
Common Units Subject to Redemption, and Management Nonvoting
Override Units were eliminated and replaced with
Stockholders Equity to reflect the new corporate structure.
The following describes the share-based compensation plans of
CALLC, CALLC II, CALLC III and CRLLC, CVR Energys wholly
owned subsidiary.
919,630
Override Operating Units at an Adjusted Benchmark Value of
$11.31 per Unit
In June 2005, CALLC issued nonvoting override operating units to
certain management members holding common units of CALLC. There
were no required capital contributions for the override
operating units. In accordance with SFAS 123(R),
Share
Based Compensation
, using the Monte Carlo method of
valuation, the estimated fair value of the override operating
units on June 24, 2005 was $3,605,000. Pursuant to the
forfeiture schedule described below, CVR Energy recognized
compensation expense over the service period for each separate
portion of the award for which the forfeiture restriction lapsed
as if the award was, in-substance, multiple awards. Compensation
expense was $602,000, $1,157,000, and $10,675,000 for the
191-day
period ending December 31, 2005, and for the years ending
December 31, 2006 and 2007, respectively. In connection
with the split of CALLC into two entities on October 16,
2007, managements equity interest in CALLC was split so
that half of managements equity interest is in CALLC and
half is in CALLC II. The restructuring resulted in a
modification of the existing awards under SFAS 123(R).
However, because the fair value of the modified award equaled
the fair value of the original award before the modification,
there was no accounting consequence as a result of the
modification. However, due to the restructuring, the employees
of CVR Energy and CVR Partners no longer hold share-based awards
in a parent company. Due to the change in status of the
employees related to the awards, CVR Energy recognized
compensation expense for the newly measured cost attributable to
the remaining vesting (service) period prospectively from the
date of the change in status, which expense is included in the
amounts noted above. Also, CVR Energy now accounts for these
awards pursuant to
EITF 00-12
following the guidance in
EITF 96-18,
which requires variable accounting in this circumstance. Using a
binomial model and a probability-weighted expected return method
which utilized CVR Energys cash flow projections resulted
in an estimated fair value of the override operating units as
noted below.
F-27
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant Date
|
|
Remeasurement Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture schedule below
|
|
Based on forfeiture schedule below
|
Grant date; fair value controlling basis
|
|
$5.16 per share
|
|
|
October 16, 2007 (date of modification) estimated fair value
|
|
|
|
$39.53
|
December 31, 2007 estimated fair value
|
|
N/A
|
|
$51.84 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
35.8%
|
72,492
Override Operating Units at a Benchmark Value of $34.72 per
Unit
On December 28, 2006, CALLC issued additional nonvoting
override operating units to a certain management member who
holds common units of CALLC. There were no required capital
contributions for the override operating units. In accordance
with SFAS 123(R), a combination of a binomial model and a
probability-weighted expected return method which utilized CVR
Energys cash flow projections resulted in an estimated
fair value of the override operating units on December 28,
2006 of $473,000. Management believed that this method was
preferable for the valuation of the override units as it allowed
a better integration of the cash flows with other inputs,
including the timing of potential exit events that impact the
estimated fair value of the override units. These override
operating units are being accounted for the same as the override
operating units with the adjusted benchmark value of $11.31 per
unit. In accordance with that accounting method noted above and
pursuant to the forfeiture schedule described below, CVR
recognized compensation expense of $3,000 and $877,000 for the
periods ending December 31, 2006 and 2007, respectively.
The amount included in the year ending December 31, 2007
includes compensation expense as a result of the restructuring
and modification of the split of CALLC into two entities, as
described above. Using a binomial model and a
probability-weighted expected return method which utilized CVR
Energys cash flow projections resulted in an estimated
fair value of the override operating units as described below.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant Date
|
|
Remeasurement Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture schedule below
|
|
Based on forfeiture schedule below
|
Grant date; fair value controlling basis
|
|
$8.15 per share
|
|
|
October 16, 2007 (date of modification) estimated fair value
|
|
|
|
$20.34
|
December 31, 2007 estimated fair value
|
|
N/A
|
|
$32.65 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
35.8%
|
F-28
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Override operating units are forfeited upon termination of
employment for cause. In the event of all other terminations of
employment, the override operating units are initially subject
to forfeiture with the number of units subject to forfeiture
reducing as follows:
|
|
|
|
|
|
|
Forfeiture
|
|
Minimum Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
On the tenth anniversary of the issuance of override operating
units, such units shall convert into an equivalent number of
override value units.
1,839,265
Override Value Units at an Adjusted Benchmark Value of $11.31
per Unit
In June 2005, CALLC issued 1,839,265 nonvoting override value
units to certain management members holding common units of
CALLC. There were no required capital contributions for the
override value units.
In accordance with SFAS 123(R), using the Monte Carlo
method of valuation, the estimated fair value of the override
value units on June 24, 2005 was $4,065,000. For the
override value units, CVR Energy is recognizing compensation
expense ratably over the implied service period of 6 years.
These override value units are being accounted for the same as
the override operating units with an adjusted benchmark value of
$11.31 per unit. In accordance with that accounting method noted
above, CVR recognized compensation expense of $395,000,
$677,000, and $12,788,000 for the
191-day
period ending December 31, 2005, and for the years ending
December 31, 2006 and 2007, respectively. The amount included in
the year ending December 31, 2007 includes compensation
expense as a result of the restructuring and modification of the
split of CALLC into two entities, as described above. Using a
binomial model and a probability-weighted expected return method
which utilized CVR Energys cash flow projections resulted
in an estimated fair value of the override value units as
described below. Significant assumptions used in the valuation
were as follows:
|
|
|
|
|
|
|
Grant Date
|
|
Remeasurement Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date; fair value controlling basis
|
|
$2.91 per share
|
|
|
October 16, 2007 (date of modification) estimated fair value
|
|
|
|
$39.53
|
December 31, 2007 estimated fair value
|
|
N/A
|
|
$51.84 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
35.8%
|
144,966
Override Value Units at a Benchmark Value of $34.72 per
Unit
On December 28, 2006, CALLC issued 144,966 additional
nonvoting override value units to a certain management member
who holds common units of CALLC. There were no required capital
contributions for the override value units.
In accordance with SFAS 123(R), a combination of a binomial
model and a probability-weighted expected return method which
utilized CVR Energys cash flow projections resulted in an
estimated fair value of the override value units on
December 28, 2006 of $945,000. Management believed that
this method was preferable for the valuation of the override
units as it allowed a better integration of the cash flows with
other inputs, including the timing of potential exit events that
impact the estimated
F-29
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
fair value of the override units. For the override value units,
CVR Energy is recognizing compensation expense ratably over the
implied service period of 6 years. These override value
units are being accounted for the same as the override operating
units with the adjusted benchmark value of $11.31 per unit. In
accordance with that accounting method noted above, CVR
recognized compensation expense of $17,000, and $718,000 for the
years ending December 31, 2006 and 2007, respectively. The
amount included in the year ending December 31, 2007
includes compensation expense as a result of the restructuring
and modification of the split of CALLC into two entities, as
described above. Using a binomial model and a
probability-weighted expected return method which utilized CVR
Energys cash flow projections resulted in an estimated
fair value of the override value units as noted below.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant Date
|
|
Remeasurement Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date; fair value controlling basis
|
|
$8.15 per share
|
|
|
October 16, 2007 (date of modification) estimated fair value
|
|
|
|
$20.34
|
December 31, 2007 estimated fair value
|
|
N/A
|
|
$32.65 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
35.8%
|
Unless the compensation committee of the board of directors of
CVR Energy takes an action to prevent forfeiture, override value
units are forfeited upon termination of employment for any
reason except that in the event of termination of employment by
reason of death or disability, all override value units are
initially subject to forfeiture with the number of units subject
to forfeiture reducing as follows:
|
|
|
|
|
|
|
Forfeiture
|
|
Minimum Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
At December 31, 2007, assuming no change in the estimated
fair value at December 31, 2007, there was approximately
$71.1 million of unrecognized compensation expense related
to nonvoting override units. This is expected to be recognized
over a period of five years as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
Year Ending December
31,
|
|
Operating Units
|
|
|
Value Units
|
|
|
2008
|
|
$
|
7,882
|
|
|
$
|
16,924
|
|
2009
|
|
|
4,087
|
|
|
|
16,924
|
|
2010
|
|
|
1,217
|
|
|
|
16,924
|
|
2011
|
|
|
|
|
|
|
7,138
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
13,186
|
|
|
$
|
57,910
|
|
|
|
|
|
|
|
|
|
|
Phantom Unit
Appreciation Plan
CVR Energy, through a wholly-owned subsidiary, has a Phantom
Unit Appreciation Plan whereby directors, employees, and service
providers may be awarded phantom points at the discretion of the
F-30
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
board of directors or the compensation committee. Holders of
service phantom points have rights to receive distributions when
holders of override operating units receive distributions.
Holders of performance phantom points have rights to receive
distributions when holders of override value units receive
distributions. There are no other rights or guarantees, and the
plan expires on July 25, 2015, or at the discretion of the
compensation committee of the board of directors of CVR Energy.
As of December 31, 2007, the issued Profits Interest
(combined phantom plan and override units) represented 15% of
combined common unit interest and Profits Interest of CVR
Energy. The Profits Interest was comprised of 11.1% and 3.9% of
override interest and phantom interest, respectively. In
accordance with SFAS 123(R), using the December 31,
2007 CVR Energy stock closing price to determine the CVR Energy
equity value, through an independent valuation process, the
service phantom interest and the performance phantom interest
were both valued at $51.84 per point. CVR has recorded
compensation expense related to the Phantom Unit Plan of
$95,000, $10,722,000, and $18,400,000 for the
191-day
period ending December 31, 2005, and for the years ending
December 31, 2006 and December 31, 2007, respectively.
$10,817,000 and $29,217,000 were recorded in personnel accruals
as of December 31, 2006 and 2007, respectively.
At December 31, 2007, and assuming no change in the
estimated fair value at December 31, 2007, there was
approximately $25.2 million of unrecognized compensation
expense related to the Phantom Unit Plan. This is expected to be
recognized over a remaining period of four years.
138,281
Override Units with a Benchmark Amount of $10
In October 2007, CALLC III issued non-voting override units to
certain management members holding common units of CALLC III.
There were no required capital contributions for the override
units. In accordance with SFAS 123(R),
Share Based
Compensation
, using a binomial and a probability-weighted
expected return method which utilized the CALLC IIIs cash
flows projections, the estimated fair value of the operating
units at December 31, 2007 was $3,000. CVR Energy
recognizes compensation costs for this plan based on the fair
value of the awards at the end of each reporting period in
accordance with
EITF 00-12
using the guidance in
EITF 96-18.
In accordance with
EITF 00-12,
as a noncontributing investor, CVR Energy also recognized income
equal to the amount that its interest in the investees net
book value has increased (that is, its percentage share of the
contributed capital recognized by the investee) as a result of
the disproportionate funding of the compensation costs. This
amount equaled the compensation expense recognized for these
awards for the year ended December 31, 2007. Pursuant to
the forfeiture schedule reflected above, CVR Energy recognized
compensation expense over this service period for each portion
of the award for which the forfeiture restriction has lapsed.
Significant Assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
Explicit Service Period
|
|
Based on forfeiture schedule above
|
December 31, 2007 estimated fair value
|
|
$0.02 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
34.7%
|
In connection with the initial public offering, the fractional
shares held by the Companys chief executive officer in the
Successors subsidiaries were exchanged at the fair value
for 247,471 shares of CVR common stock. This exchange
resulted in the elimination of the minority interest, the
reversal of previous fair value adjustments of $1,053,000 in
Members Equity, the
step-up
in
property, plant and equipment of $974,000, and the recognition
of a related deferred tax liability of $389,000.
In February 2008, CALLC III issued additional non-voting
override units to management members.
F-31
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Long Term
Incentive Plan
The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP,
permits the grant of options, stock appreciation rights, or
SARs, restricted stock, restricted stock units, dividend
equivalent rights, share awards and performance awards
(including performance share units, performance units and
performance-based restricted stock). Individuals who are
eligible to receive awards and grants under the LTIP include the
Companys subsidiaries employees, officers,
consultants, advisors and directors. A summary of the principal
features of the LTIP is provided below. As of December 31,
2007, no awards had been made under the LTIP to any of the
Companys executive officers.
Shares Available for Issuance.
The LTIP
authorizes a share pool of 7,500,000 shares of the
Companys common stock, 1,000,000 of which may be issued in
respect of incentive stock options. Whenever any outstanding
award granted under the LTIP expires, is canceled, is settled in
cash or is otherwise terminated for any reason without having
been exercised or payment having been made in respect of the
entire award, the number of shares available for issuance under
the LTIP shall be increased by the number of shares previously
allocable to the expired, canceled, settled or otherwise
terminated portion of the award. As of December 31, 2007,
7,463,600 shares of common stock were available for
issuance under the LTIP.
On October 24, 2007, 17,500 shares of non-vested stock
having a fair value of $365,000 at the date of grant were issued
to outside directors. Although ownership of the shares does not
transfer to the recipients until the shares have vested,
recipients have dividend and voting rights on these shares from
the date of grant. The fair value of each share of non-vested
stock was measured based on the market price of the common stock
as of the date of grant and will be amortized over the
respective vesting periods. One-third will vest on
October 24, 2010.
Options to purchase 10,300 common shares at an exercise price of
$19.00 per share were granted to outside directors on
October 22, 2007. Options to purchase 8,600 common shares
at an exercise price of $24.73 per share were granted to outside
directors on December 21, 2007.
A summary of the status of CVRs non-vested shares as of
December 31, 2007 and changes during the year ended
December 31, 2007 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant-Date
|
|
Non-Vested Shares
|
|
Shares
|
|
|
Fair Value
|
|
|
|
(In 000s)
|
|
|
|
|
|
Non-vested at December 31, 2006
|
|
$
|
|
|
|
$
|
|
|
Granted
|
|
|
18
|
|
|
|
20.88
|
|
Vested
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2007
|
|
$
|
18
|
|
|
$
|
20.88
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, there was approximately
$0.3 million of total unrecognized compensation cost
related to non-vested shares to be recognized over a
weighted-average period of approximately one year. Total
compensation expense recorded in 2007 related to the nonvested
stock was $42,000.
F-32
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Activity and price information regarding CVRs stock
options granted are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
|
|
|
|
Exercise
|
|
|
Contractual
|
|
Options
|
|
Shares
|
|
|
Price
|
|
|
Term
|
|
|
|
(In 000s)
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2006
|
|
|
|
|
|
$
|
|
|
|
|
|
|
Granted
|
|
|
19
|
|
|
$
|
21.61
|
|
|
|
9.89
|
|
Exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2007
|
|
|
19
|
|
|
$
|
21.61
|
|
|
|
9.89
|
|
Vested or expected to vest at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant-date fair value of options granted
during the year ended December 31, 2007 was $12.47 per
share. Total compensation expense recorded in 2007 related to
the stock options was $15,000.
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
As restated()
|
|
|
Finished goods
|
|
$
|
59,722
|
|
|
$
|
109,394
|
|
Raw materials and catalysts
|
|
|
60,810
|
|
|
|
92,104
|
|
In-process inventories
|
|
|
18,441
|
|
|
|
29,817
|
|
Parts and supplies
|
|
|
22,460
|
|
|
|
23,340
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
161,433
|
|
|
$
|
254,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
F-33
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(6)
|
Property, Plant,
and Equipment
|
A summary of costs for property, plant, and equipment is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
Land and improvements
|
|
$
|
11,028
|
|
|
$
|
13,058
|
|
Buildings
|
|
|
11,042
|
|
|
|
17,541
|
|
Machinery and equipment
|
|
|
864,140
|
|
|
|
1,108,858
|
|
Automotive equipment
|
|
|
4,175
|
|
|
|
5,171
|
|
Furniture and fixtures
|
|
|
5,364
|
|
|
|
6,304
|
|
Leasehold improvements
|
|
|
887
|
|
|
|
929
|
|
Construction in progress
|
|
|
184,531
|
|
|
|
182,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,081,167
|
|
|
|
1,333,907
|
|
Accumulated depreciation
|
|
|
74,011
|
|
|
|
141,733
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,007,156
|
|
|
$
|
1,192,174
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest recognized as a reduction in interest
expense for the years ended December 31, 2006, and
December 31, 2007 totaled approximately $11,613,000 and
$12,049,000, respectively.
|
|
(7)
|
Goodwill and
Intangible Assets
|
In connection with the Acquisition described in Note 1,
Successor recorded goodwill of $83,775,000.
SFAS No. 142,
Goodwill and Other Intangible
Assets
, provides that goodwill and other intangible assets
with indefinite lives shall not be amortized but shall be tested
for impairment on an annual basis. In accordance with
SFAS 142, Successor completed its annual test for
impairment of goodwill as of November 1, 2006 and 2007.
Based on the results of the test, no impairment of goodwill was
recorded as of December 31, 2006 or December 31, 2007.
The annual review of impairment is performed by comparing the
carrying value of the applicable reporting unit to its estimated
fair value using a combination of the discounted cash flow
analysis and market approach. CVRs reporting units are
defined as operating segments, as such all goodwill impairment
testing is done at each operating segment.
Contractual agreements with a fair market value of $1,322,000
were acquired in the Acquisition described in Note 1. The
intangible value of these agreements is amortized over the life
of the agreements through June 2025. Amortization expense of
$313,000, $370,000, and $165,000 was recorded in depreciation
and amortization for the
233-days
ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007, respectively.
Estimated amortization of the contractual agreements is as
follows (in thousands):
|
|
|
|
|
|
|
Contractual
|
|
Year Ending December
31,
|
|
Agreements
|
|
|
2008
|
|
|
64
|
|
2009
|
|
|
33
|
|
2010
|
|
|
33
|
|
2011
|
|
|
33
|
|
2012
|
|
|
28
|
|
Thereafter
|
|
|
282
|
|
|
|
|
|
|
|
|
|
473
|
|
|
|
|
|
|
F-34
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(8)
|
Deferred
Financing Costs
|
Deferred financing costs of $10,009,000 were paid in conjunction
with a debt financing in 2004. The unamortized amount of these
deferred financing costs of $8,094,000 related to the
May 10, 2004 refinancing were written off when the related
debt was extinguished upon the Acquisition described in
Note 1 and these costs were included in loss on
extinguishment of debt for the 174 days ended June 23,
2005. For the 174 days ended June 23, 2005,
amortization of deferred financing costs reported as interest
expense and other financing costs was $812,000, using the
effective-interest amortization method.
Deferred financing costs of $24,628,000 were paid in the
Acquisition described in Note 1. Effective
December 28, 2006, the Company amended and restated its
credit agreement with a consortium of banks, additionally
capitalizing $8,462,000 in debt issuance costs. This amendment
and restatement was within the scope of the
EITF 96-19,
Debtors Accounting for Modification or Exchange of Debt
Instruments
, as well as
EITF 98-14,
Debtors Accounting for Changes in
Line-of-Credit
or Revolving-Debt Arrangements
. In accordance with that
guidance, a portion of the unamortized loan costs of $16,959,000
from the original credit facility as well as additional finance
and legal charges associated with the second amended and
restated credit facility of $901,000 were included in loss on
extinguishment of debt for the year December 31, 2006. The
remaining costs are being amortized over the life of the related
debt instrument. Additionally, a prepayment penalty of
$5,500,000 on the previous credit facility was also paid and
expensed and included in loss on extinguishment of debt for the
year ended December 31, 2006. For the 233 days ended
December 31, 2005, the years ended December 31, 2006,
and December 31, 2007, amortization of deferred financing
costs reported as interest expense and other financing costs
totaled $1,751,000, $3,337,000, and $1,947,000, respectively,
using the effective-interest amortization method for the term
debt and the straight-line method for the letter of credit
facility and revolving loan facility.
Deferred financing costs of $2,088,000 were paid in conjunction
with three new credit facilities entered into August 2007 as a
result of the flood and crude oil discharge. The unamortized
amount of these deferred financing costs of $1,258,000 were
written off when the related debt was extinguished upon the
consummation of the initial public offering and these costs were
included in loss on extinguishment of debt for the year ended
December 31, 2007. Amortization of deferred financing costs
reported as interest expense and other financing costs was
$831,000 using the effective-interest amortization method.
Deferred financing costs consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
Deferred financing costs
|
|
$
|
11,065
|
|
|
$
|
12,278
|
|
Less accumulated amortization
|
|
|
21
|
|
|
|
2,778
|
|
|
|
|
|
|
|
|
|
|
Unamortized deferred financing costs
|
|
|
11,044
|
|
|
|
9,500
|
|
Less current portion
|
|
|
1,916
|
|
|
|
1,985
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,128
|
|
|
$
|
7,515
|
|
|
|
|
|
|
|
|
|
|
F-35
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Estimated amortization of deferred financing costs is as follows
(in thousands):
|
|
|
|
|
|
|
Deferred
|
|
Year Ending December
31,
|
|
Financing
|
|
|
2008
|
|
$
|
1,985
|
|
2009
|
|
|
1,968
|
|
2010
|
|
|
1,953
|
|
2011
|
|
|
1,436
|
|
2012
|
|
|
1,426
|
|
Thereafter
|
|
|
732
|
|
|
|
|
|
|
|
|
$
|
9,500
|
|
|
|
|
|
|
|
|
(9)
|
Note Payable and
Capital Lease Obligations
|
The Company entered into an insurance premium finance agreement
in July 2007 to finance the purchase of its property, liability,
cargo and terrorism policies. The approximately
$3.4 million note will be repaid in equal monthly
installments of $0.8 million with final payment in April
2008.
The Company entered into two capital leases in 2007 to lease
platinum required in the manufacturing of a new catalyst. The
leases will terminate on the date an equal amount of platinum is
returned to each lessor with the difference to be paid in cash.
At December 31, 2007 the lease obligations were recorded at
approximately $8.2 million on the consolidated balance
sheet.
On June 30, 2007, torrential rains in southeast Kansas
caused the Verdigris River to overflow its banks and flood the
town of Coffeyville, Kansas. As a result, the Companys
refinery and nitrogen fertilizer plant were severely flooded
resulting in significant damage to the refinery assets. The
nitrogen fertilizer facility also sustained damage, but to a
much lesser degree. The Company maintains property damage
insurance which includes damage caused by a flood of up to
$300 million per occurrence subject to deductibles and
other limitations. The deductible associated with the property
damage is $2.5 million.
Management is working closely with the Companys insurance
carriers and claims adjusters to ascertain the full amount of
insurance proceeds due to the Company as a result of the damages
and losses. The Company has recognized a receivable of
approximately $85.3 million from insurance at
December 31, 2007 which management believes is probable of
recovery from the insurance carriers. While management believes
that the Companys property insurance should cover
substantially all of the estimated total physical damage to the
property, the Companys insurance carriers have cited
potential coverage limitations and defenses that might preclude
such a result.
The Companys insurance policies also provide coverage for
interruption to the business, including lost profits, and
reimbursement for other expenses and costs the Company has
incurred relating to the damages and losses suffered for
business interruption. This coverage, however, only applies to
losses incurred after a business interruption of 45 days.
Because the fertilizer plant was restored to operation within
this
45-day
period and the refinery restarted its last operating unit in
48 days, a substantial portion of the lost profits incurred
because of the flood cannot be claimed under insurance. The
Company is assessing its policies to determine how much, if any,
of its lost profits after the
45-day
period are recoverable. No amounts for recovery of lost profits
under the Companys business interruption policy have been
recorded in the accompanying consolidated financial statements.
As of December 31, 2007, the Company has recorded pretax
costs of approximately $41.5 million associated with the
flood and related crude oil discharge as discussed in
Note 15, Commitments and Contingent
Liabilities, including $7.2 million in the fourth
quarter of 2007. These amounts were net of
F-36
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
anticipated insurance recoveries of approximately
$105.3 million. The components of the net costs as of
December 31, 2007 include $3.6 million for uninsured
losses within the Companys insurance deductibles;
$7.6 million for depreciation for the temporarily idled
facilities; $6.8 million as a result of other uninsured
expenses incurred which included salaries of $1.2 million,
professional fees of $1.9 million and other miscellaneous
amounts of $3.7 million. The $41.5 million net costs
also included approximately $23.5 million recorded with
respect to the environmental remediation and property damage as
discussed in Note 15, Commitments and Contingent
Liabilities. These costs are reported in Net costs
associated with flood in the Consolidated Statements of
Operations.
Total gross costs recorded due to the flood and related oil
discharge that were included in the statement of operations for
the year ended December 31, 2007 were approximately
$146.8 million. Of these gross costs for the year ended
December 31, 2007, approximately $101.9 million were
associated with repair and other matters as a result of the
flood damage to the Companys facilities. Included in this
cost was $7.6 million of depreciation for temporarily idled
facilities, $6.1 million of salaries, $2.2 million of
professional fees and $86.0 million for other repair and
related costs. There were approximately $44.9 million costs
recorded for the year ended December 31, 2007 related to
the third party and property damage remediation as a result of
the crude oil discharge. Total anticipated insurance recoveries
of approximately $105.3 million were recorded and netted
with the gross costs as of December 31, 2007. As of
December 31, 2007, CVR had received insurance proceeds of
$10.0 million under its property insurance policy, and an
additional $10.0 million under its environmental policies
related to the recovery of certain costs associated with the
crude oil discharge. Subsequent to December 31, 2007, CVR
received insurance proceeds of $1.5 million under the
Builders Risk Insurance Policy. See Note 15,
Commitments and Contingent Liabilities for
additional information regarding environmental and other
contingencies relating to the crude oil discharge that occurred
on July 1, 2007. Accounts receivable from insurers for
flood related matters approximated $85.3 million at
December 31, 2007, for which we believe collection is
probable, including $11.4 million related to the crude oil
discharge and $73.9 million as a result of the flood damage
to the Companys facilities.
The Company anticipates that approximately $6.0 million in
additional third party costs related to the repair of flood
damaged property will be recorded in future periods. Although
the Company believes that it will recover substantial sums under
its insurance policies, the Company is not sure of the ultimate
amount or timing of such recovery because of the difficulty
inherent in projecting the ultimate resolution of the
Companys claims. The difference between what the Company
ultimately receives under its insurance policies compared to
what has been recorded and described above could be material to
the consolidated financial statements.
F-37
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Income tax expense (benefit) is comprised of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As restated()
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
26,145
|
|
|
|
$
|
29,000
|
|
|
$
|
26,096
|
|
|
$
|
(26,814
|
)
|
State
|
|
|
6,099
|
|
|
|
|
6,457
|
|
|
|
6,974
|
|
|
|
(4,017
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
32,244
|
|
|
|
|
35,457
|
|
|
|
33,070
|
|
|
|
(30,831
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
3,083
|
|
|
|
|
(80,500
|
)
|
|
|
69,836
|
|
|
|
(21,434
|
)
|
State
|
|
|
721
|
|
|
|
|
(17,925
|
)
|
|
|
16,934
|
|
|
|
(36,250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
3,804
|
|
|
|
|
(98,425
|
)
|
|
|
86,770
|
|
|
|
(57,684
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
36,048
|
|
|
|
$
|
(62,968
|
)
|
|
$
|
119,840
|
|
|
$
|
(88,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a reconciliation of total income tax expense
(benefit) to income tax expense (benefit) computed by applying
the statutory federal income tax rate (35%) to income before
income tax expense (benefit) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As restated()
|
|
Tax computed at federal statutory rate
|
|
$
|
30,956
|
|
|
|
$
|
(63,744
|
)
|
|
$
|
108,994
|
|
|
$
|
(54,720
|
)
|
State income taxes, net of federal tax benefit (expense)
|
|
|
4,433
|
|
|
|
|
(7,454
|
)
|
|
|
15,618
|
|
|
|
(6,382
|
)
|
State tax incentives, net of deferred federal tax expense
|
|
|
|
|
|
|
|
|
|
|
|
(78
|
)
|
|
|
(19,792
|
)
|
Manufacturing activities deduction
|
|
|
(825
|
)
|
|
|
|
(897
|
)
|
|
|
(1,089
|
)
|
|
|
|
|
Federal tax credit for production of ultra-low sulfur diesel fuel
|
|
|
|
|
|
|
|
|
|
|
|
(4,462
|
)
|
|
|
(17,259
|
)
|
Loss on unexercised option agreements with no tax benefit to
Successor
|
|
|
|
|
|
|
|
8,750
|
|
|
|
|
|
|
|
|
|
Non-deductible share based compensation
|
|
|
1,395
|
|
|
|
|
349
|
|
|
|
649
|
|
|
|
8,771
|
|
Other, net
|
|
|
89
|
|
|
|
|
28
|
|
|
|
208
|
|
|
|
867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
36,048
|
|
|
|
$
|
(62,968
|
)
|
|
$
|
119,840
|
|
|
$
|
(88,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
F-38
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Certain provisions of the American Jobs Creation Act of 2004
(the Act) are providing federal income tax benefits to CVR. The
Act created Internal Revenue Code section 199 which
provides an income tax benefit to domestic manufacturers. CVR
recognized an income tax benefit related to this manufacturing
deduction of approximately $825,000, $897,000, $1,089,000, and
$0 for the 174 days ended June 23, 2005, the
233 days ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007, respectively.
The Act also provides for a $0.05 per gallon income tax credit
on compliant diesel fuel produced up to an amount equal to the
remaining 25% of the qualified capital costs. CVR recognized an
income tax benefit of approximately $4,462,000 and $17,259,000
on a credit of approximately $6,865,000 and $26,552,000 related
to the production of ultra low sulfur diesel for the years ended
December 31, 2006, and December 31, 2007, respectively.
The loss on unexercised option agreements of $25,000,000 in 2005
occurred at Coffeyville Acquisition LLC, and the tax deduction
related to the loss was passed through to the partners of
Coffeyville Acquisition LLC in the 233 days ended
December 31, 2005.
The income tax effect of temporary differences that give rise to
significant portions of the deferred income tax assets and
deferred income tax liabilities at December 31, 2006 and
2007 are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
As restated()
|
|
|
|
(in thousands)
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
150
|
|
|
$
|
156
|
|
Personnel accruals
|
|
|
5,072
|
|
|
|
12,757
|
|
Inventories
|
|
|
673
|
|
|
|
671
|
|
Unrealized derivative losses, net
|
|
|
40,389
|
|
|
|
85,650
|
|
Low sulfur diesel fuel credit carry forward
|
|
|
|
|
|
|
17,860
|
|
State net operating loss carry forwards, net of federal expense
|
|
|
|
|
|
|
4,158
|
|
Accrued expenses
|
|
|
249
|
|
|
|
1,713
|
|
Deferred revenue
|
|
|
|
|
|
|
3,403
|
|
State tax credit carryforward, net of federal expense
|
|
|
|
|
|
|
17,475
|
|
Other
|
|
|
|
|
|
|
353
|
|
|
|
|
|
|
|
|
|
|
Total Gross deferred income tax assets
|
|
|
46,533
|
|
|
|
144,196
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant, and equipment
|
|
|
(309,472
|
)
|
|
|
(348,902
|
)
|
Prepaid Expenses
|
|
|
(1,140
|
)
|
|
|
(3,233
|
)
|
Other
|
|
|
(1,155
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gross deferred income tax liabilities
|
|
|
(311,767
|
)
|
|
|
(352,135
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liabilities
|
|
$
|
(265,234
|
)
|
|
$
|
(207,939
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
At December 31, 2007, CVR has net operating loss
carryforwards for state income tax purposes of approximately
$86.9 million, which are available to offset future state
taxable income. The net operating loss carryforwards, if not
utilized, will expire between 2012 and 2027.
F-39
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
At December 31, 2007, CVR has federal tax credit
carryforwards related to the production of low sulfur diesel
fuel of approximately $17.9 million, which are available to
reduce future federal regular income taxes. These credits, if
not used, will expire in 2027. CVR also has Kansas state income
tax credits of approximately $26.9 million, which are
available to reduce future Kansas state regular income taxes.
These credits, if not used, will expire in 2017.
In assessing the realizability of deferred tax assets including
net operating loss and credit carryforwards, management
considers whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon
the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities,
projected future taxable income, and tax planning strategies in
making this assessment. Based upon the level of historical
taxable income and projections for future taxable income over
the periods in which the deferred tax assets are deductible,
management believes it is more likely than not that CVR will
realize the benefits of these deductible differences. Therefore,
CVR has not recorded any valuation allowances against deferred
tax assets as of December 31, 2006 or December 31,
2007.
CVR adopted FIN 48 effective January 1, 2007.
FIN 48 clarifies the accounting for uncertainty in income
taxes recognized in the financial statements. If the probability
of sustaining a tax position is at least more likely than not,
then the tax position is warranted and recognition should be at
the highest amount which is greater than 50% likely of being
realized upon ultimate settlement. As of the date of adoption of
FIN 48 and at December 31, 2007, CVR did not believe
it had any tax positions that met the criteria for uncertain tax
positions. As a result, no amounts were recognized as a
liability for uncertain tax positions.
CVR recognizes interest and penalties on uncertain tax positions
and income tax deficiencies in income tax expense. CVR did not
recognize any interest or penalties in 2007 for uncertain tax
positions or income tax deficiencies. At December 31, 2007,
CVRs tax returns are open to examination for federal and
various states for the 2004 to 2007 tax years.
A reconciliation of the unrecognized tax benefits for the year
ended December 31, 2007, is as follows:
|
|
|
|
|
Balance as of January 1, 2007
|
|
$
|
0
|
|
Increase and decrease in prior year tax positions
|
|
|
|
|
Increases and decrease in current year tax positions
|
|
|
|
|
Settlements
|
|
|
|
|
Reductions related to expirations of statute of limitations
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
$
|
0
|
|
|
|
|
|
|
Effective May 10, 2004, Immediate Predecessor entered into
a term loan of $150,000,000 and a $75,000,000 revolving loan
facility with a syndicate of banks, financial institutions, and
institutional lenders. Both loans were secured by substantially
all of the Immediate Predecessors real and personal
property, including receivables, contract rights, general
intangibles, inventories, equipment, and financial assets.
Outstanding borrowings on June 23, 2005 were repaid in
connection with the Subsequent Acquisition as described in
Note 1.
Effective June 24, 2005, Successor entered into a first
lien credit facility and a guaranty agreement with two banks and
one related party institutional lender (see Note 17). The credit
facility was in an aggregate amount not to exceed $525,000,000,
consisting of $225,000,000 Tranche B Term Loans;
$50,000,000 of Delayed Draw Term Loans available for the first
18 months of the agreement and subject to accelerated
payment terms; a $100,000,000 Revolving Loan Facility; and a
Funded
F-40
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Letters of Credit Facility (Funded Facility) of $150,000,000.
The credit facility was secured by substantially all of
Successors assets. Outstanding borrowings on
December 28, 2006 were repaid in connection with the
refinancing described below.
The Term Loans and Revolving Loan Facility provided CVR the
option of a
3-month
LIBOR rate plus 2.5% per annum (rounded up to the next whole
multiple of 1/16 of 1%) or an Index Rate (to be based on the
current prime rate plus 1.5%). Interest was paid quarterly when
using the Index Rate and at the expiration of the LIBOR term
selected when using the LIBOR rate; interest varied with the
Index Rate or LIBOR rate in effect at the time of the borrowing.
The annual fee for the Funded Facility was 2.725% of outstanding
Funded Letters of Credit.
Effective June 24, 2005, Successor entered into a second
lien $275,000,000 term loan and guaranty agreement with a bank
and a related party institutional lender (see Note 17). CVR
had the option of a
3-month
LIBOR rate plus 6.75% per annum (rounded up to the next whole
multiple of 1/16 of 1%) or an Index Rate (to be based on the
current prime rate plus 5.75%). The loan was secured by a second
lien on substantially all of CVRs assets. Outstanding
borrowings on December 28, 2006 were repaid in connection
with the refinancing described below.
On December 28, 2006, Successor entered into a second
amended and restated credit and guaranty agreement (the credit
and guaranty agreement) with two banks and one related party
institutional lender (see Note 17). The credit facility was
in an aggregate amount not to exceed $1,075,000,000, consisting
of $775,000,000 Tranche D Term Loans; a $150,000,000
Revolving Loan Facility; and a Funded Facility of $150,000,000.
The credit facility was secured by substantially all of
CVRs assets. At December 31, 2006, and
December 31, 2007, $775,000,000 and $489,202,000 of
Tranche D Term Loans was outstanding, and there was no
outstanding balance on the Revolving Loan Facility. At
December 31, 2006, and December 31, 2007, Successor
had $150,000,000 in Funded Letters of Credit outstanding to
secure payment obligations under derivative financial
instruments (see Note 16).
At December 31, 2006, the Term Loan and Revolving Loan
Facility provided CVR the option of a
3-month
LIBOR rate plus 3.0% per annum (rounded up to the next whole
multiple of 1/16 of 1%) or an Index Rate (to be based on the
current prime rate plus 2.0%). At December 31, 2007, the
Term Loan and Revolving Loan Facility provide CVR the option of
a
3-month
LIBOR rate plus 2.75% per annum (rounded up to the next whole
multiple of 1/16 of 1%) or an Index Rate (to be based on the
current prime rate plus 1.75%). Interest is paid quarterly when
using the Index Rate and at the expiration of the LIBOR term
selected when using the LIBOR rate; interest varies with the
Index Rate or LIBOR rate in effect at the time of the borrowing.
The interest rate on December 31, 2006 and
December 31, 2007 was 8.36%and 7.98%, respectively. The
annual fee for the Funded Facility was 3.225% and 2.975%,
respectively at December 31, 2006 and December 31,
2007 of outstanding Funded Letters of Credit.
F-41
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The loan and security agreements contain customary restrictive
covenants applicable to CVR, including limitations on the level
of additional indebtedness, commodity agreements, capital
expenditures, payment of dividends, creation of liens, and sale
of assets. These covenants also require CVR to maintain
specified financial ratios as follows:
First Lien Credit
Facility
|
|
|
|
|
|
|
|
|
|
|
Minimum
|
|
|
|
|
|
|
Interest
|
|
|
Maximum
|
|
Fiscal Quarter Ending
|
|
Coverage Ratio
|
|
|
Leverage Ratio
|
|
|
March 31, 2008
|
|
|
3.25:1.00
|
|
|
|
3.25:1.00
|
|
June 30, 2008
|
|
|
3.25:1.00
|
|
|
|
3.00:1.00
|
|
September 30, 2008
|
|
|
3.25:1.00
|
|
|
|
2.75:1.00
|
|
December 31, 2008
|
|
|
3.25:1.00
|
|
|
|
2.50:1.00
|
|
March 31, 2009 December 31, 2009
|
|
|
3.75:1.00
|
|
|
|
2.25:1.00
|
|
March 31, 2010 and thereafter
|
|
|
3.75:1.00
|
|
|
|
2.00:1.00
|
|
Failure to comply with the various restrictive and affirmative
covenants of the loan agreements could negatively affect
CVRs ability to incur additional indebtedness
and/or
pay
required distributions. Successor is required to measure its
compliance with these financial ratios and covenants quarterly
and was in compliance with all covenants and reporting
requirements under the terms of the agreement at
December 31, 2006 and December 31, 2007. As required
by the debt agreements, CVR has entered into interest rate swap
agreements (as described in Note 16) that are required
to be held for the remainder of the stated term.
Long-term debt at December 31, 2007 consisted of the
following future maturities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
|
|
|
|
December 31,
|
|
|
Amount
|
|
|
First lien Tranche D term loans; principal payments
|
|
|
2008
|
|
|
$
|
4,874
|
|
of .25% of the principal balance due quarterly
|
|
|
2009
|
|
|
|
4,825
|
|
commencing April 2007, increasing to 23.5% of the
|
|
|
2010
|
|
|
|
4,777
|
|
principal balance due quarterly commencing April 2013,
|
|
|
2011
|
|
|
|
4,730
|
|
with a final payment of the aggregate remaining unpaid
|
|
|
2012
|
|
|
|
4,682
|
|
principal balance due December 2013
|
|
|
Thereafter
|
|
|
|
465,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
489,202
|
|
|
|
|
|
|
|
|
|
|
Commencing with fiscal year 2007, CVR shall prepay the loans in
an aggregate amount equal to 75% of Consolidated Excess Cash
Flow (as defined in the credit and guaranty agreement, which
includes a formulaic calculation consisting of many financial
statement items, starting with consolidated Earnings Before
Interest Taxes Depreciation and Amortization) less 100% of
voluntary prepayments made during that fiscal year. Commencing
with fiscal year 2008, the aggregate amount changes to 50% of
Consolidated Excess Cash Flow provided the total leverage ratio
is less than 1:50:1:00 or 25% of Consolidated Excess Cash Flow
provided the total leverage ratio is less than 1:00:1:00.
At December 31, 2007, Successor had $5.8 million in
letters of credit outstanding to collateralize its environmental
obligations, $30.6 million in letters of credit outstanding
to secure transportation services for crude oil, and
$3.0 million in support of surety bonds in place to support
state and federal excise tax for refined fuels. These letters of
credit were outstanding against the December 28, 2006
Revolving Loan Facility. The fee for the revolving letters of
credit is 3.00%.
F-42
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
The Revolving Loan Facility has a current expiration date of
December 28, 2012. The Funded Facility has a current
expiration date of December 28, 2010.
As a result of the flood and crude oil discharge, the
Companys subsidiaries entered into three new credit
facilities in August 2007. Coffeyville Resources, LLC entered
into a $25 million senior secured term loan (the
$25 million secured facility). The facility was secured by
the same collateral that secures the Companys existing
Credit Facility. Interest was payable in cash, at the
Companys option, at the base rate plus 1.00% or at the
reserve adjusted Eurodollar rate plus 2.00%. Coffeyville
Resources, LLC also entered into a $25 million senior
unsecured term loan (the $25 million unsecured facility).
Interest was payable in cash, at the Companys option, at
the base rate plus 1.00% or at the reserve adjusted Eurodollar
rate plus 2.00%. A subsidiary of Coffeyville Acquisition LLC,
Coffeyville Refining & Marketing Holdings, Inc.,
entered into a $75 million senior unsecured term loan (the
$75 million unsecured facility). Drawings could be made
from time to time in amounts of at least $5 million.
Interest accrued, at the Companys option, at the base rate
plus 1.50% or at the reserve adjusted Eurodollar rate plus
2.50%. Interest was paid by adding such interest to the
principal amount of loans outstanding. In addition, a commitment
fee equal to 1.00% accrued and was paid by adding such fees to
the principal amount of loans outstanding.
All indebtedness outstanding under the $25 million secured
facility and the $25 million unsecured facility was repaid
in October 2007 with the proceeds of the Companys initial
public offering, and all three facilities were terminated at
that time.
|
|
(13)
|
Pro Forma
Earnings Per Share
|
On October 26, 2007, the Company completed the initial
public offering of 23,000,000 shares of its common stock.
Also, in connection with the initial public offering, a
reorganization of entities under common control was consummated
whereby the Company became the indirect owner of the
subsidiaries of CALLC and CALLC II and all of its refinery and
fertilizer assets. This reorganization was accomplished by the
Company issuing 62,866,720 shares of its common stock to
CALLC and CALLC II, its majority stockholder, in conjunction
with the merger of two newly formed direct subsidiaries of CVR.
Immediately following the completion of the offering, there were
86,141,291 shares of common stock outstanding, excluding
any non-vested shares issued. See Note 1,
Organization and History of Company.
The computation of basic and diluted earnings per share for the
years ended December 31, 2006 and December 31, 2007
are calculated on a pro forma basis assuming the capital
structure in place after the completion of the offering was in
place for the entire year for both 2006 and 2007.
F-43
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Pro forma earnings (loss) per share for the years ended
December 31, 2006 and December 31, 2007 is calculated
as noted below. For the year ended December 31, 2007,
17,500 non-vested common shares and 18,900 of common stock
options have been excluded from the calculation of pro-forma
diluted earnings per share because the inclusion of such common
stock equivalents in the number of weighted average shares
outstanding would be anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
2006
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
(As restated)()
|
|
|
|
(in thousands)
|
|
|
Net income (loss)
|
|
$
|
191,571
|
|
|
$
|
(67,618
|
)
|
Pro forma weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Original CVR common shares
|
|
|
100
|
|
|
|
100
|
|
Effect of 628,667.20 to 1 stock split
|
|
|
62,866,620
|
|
|
|
62,866,620
|
|
Issuance of common shares to management in exchange for
subsidiary shares
|
|
|
247,471
|
|
|
|
247,471
|
|
Issuance of common shares to employees
|
|
|
27,100
|
|
|
|
27,100
|
|
Issuance of common shares in the initial public offering
|
|
|
23,000,000
|
|
|
|
23,000,000
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Dilutive securities issuance of nonvested common
shares to board of directors
|
|
|
17,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
|
|
|
Pro forma basic earnings (loss) per share
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
Pro forma dilutive earnings (loss) per share
|
|
$
|
2.22
|
|
|
$
|
(0.78
|
)
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
CVR sponsors two defined-contribution 401(k) plans (the Plans)
for all employees. Participants in the Plans may elect to
contribute up to 50% of their annual salaries, and up to 100% of
their annual income sharing. CVR matches up to 75% of the first
6% of the participants contribution for the nonunion plan
and 50% of the first 6% of the participants contribution
for the union plan. Both plans are administered by CVR and
contributions for the union plan are determined in accordance
with provisions of negotiated labor contracts. Participants in
both Plans are immediately vested in their individual
contributions. Both Plans have a three year vesting schedule for
CVRs matching funds and contain a provision to count
service with any predecessor organization. Successors
contributions under the Plans were $662,000, $447,000,
$1,375,000, and $1,513,000 for the 174 days ended
June 23, 2005, the 233 days ended December 31,
2005, and the years ended December 31, 2006 and
December 31, 2007, respectively.
F-44
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(15)
|
Commitments and
Contingent Liabilities
|
The minimum required payments for CVRs lease agreements
and unconditional purchase obligations are as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Unconditional
|
|
Year Ending December
31,
|
|
Leases
|
|
|
Purchase Obligations
|
|
|
2008
|
|
|
4,207
|
|
|
|
25,235
|
|
2009
|
|
|
3,271
|
|
|
|
25,249
|
|
2010
|
|
|
1,679
|
|
|
|
52,781
|
|
2011
|
|
|
947
|
|
|
|
50,958
|
|
2012
|
|
|
195
|
|
|
|
48,352
|
|
Thereafter
|
|
|
10
|
|
|
|
366,363
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,309
|
|
|
$
|
568,938
|
|
|
|
|
|
|
|
|
|
|
CVR leases various equipment and real properties under long-term
operating leases. For the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007, lease expense
totaled approximately $1,755,000, $1,737,000, $3,822,000, and
$3,854,000, respectively. The lease agreements have various
remaining terms. Some agreements are renewable, at CVRs
option, for additional periods. It is expected, in the ordinary
course of business, that leases will be renewed or replaced as
they expire.
CVR licenses a gasification process from a third party
associated with gasifier equipment used in the Nitrogen
Fertilizer segment. The royalty fees for this license are
incurred as the equipment is used and are subject to a cap which
was paid in full in 2007. At December 31, 2006,
approximately $1,615,000 was included in accounts payable for
this agreement. Royalty fee expense reflected in direct
operating expenses (exclusive of depreciation and amortization)
for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007 was
$1,042,000, $915,000, $2,135,000, and $1,035,000, respectively.
CRNF has an agreement with the City of Coffeyville pursuant to
which it must make a series of future payments for electrical
generation transmission and city margin. As of December 31,
2007, the remaining obligations of CRNF totaled
$19.6 million through December 31, 2019. Total minimum
annual committed contractual payments under the agreement will
be $1.7 million.
CRRM has a Pipeline Construction, Operation and Transportation
Commitment Agreement with Plains Pipeline, L.P. (Plains
Pipeline) pursuant to which Plains Pipeline constructed a crude
oil pipeline from Cushing, Oklahoma to Caney, Kansas. The term
of the agreement is 20 years from when the pipeline became
operational on March 1, 2005. Pursuant to the agreement,
CRRM must transport approximately 80,000 barrels per day of
its crude oil requirements for the Coffeyville refinery at a
fixed charge per barrel for the first five years of the
agreement. For the final fifteen years of the agreement, CRRM
must transport all of its non-gathered crude oil up to the
capacity of the Plains Pipeline. The rate is subject to a
Federal Energy Regulatory Commission (FERC) tariff and is
subject to change on an annual basis per the agreement. Lease
expense associated with this agreement and included in cost of
product sold (exclusive of depreciation and amortization) for
the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007 totaled
approximately $2,603,000, $4,372,000, $8,751,000, and
$7,214,000, respectively.
During 1997, Farmland (subsequently assigned to CRP) entered
into an Agreement of Capacity Lease and Operating Agreement with
Williams Pipe Line Company (subsequently assigned to Magellan
Pipe Line Company, L.P. (Magellan)) pursuant to which CRP leases
pipeline capacity in certain pipelines between Coffeyville,
Kansas and Caney, Kansas and between Coffeyville, Kansas and
Independence,
F-45
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Kansas. Pursuant to this agreement, CRP was obligated to pay a
fixed monthly charge to Magellan for annual leased capacity of
6,300,000 barrels until the expiration of the agreement on
April 30, 2007. Lease expense associated with this
agreement and included in cost of product sold (exclusive of
depreciation and amortization) for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007 totaled
approximately $233,000, $194,000, $504,000, and $116,000,
respectively.
During 2005, CRRM amended a Pipeline Capacity Lease Agreement
with
Mid-America
Pipeline Company (MAPL) pursuant to which CRRM leases pipeline
capacity in an outbound MAPL-operated pipeline between
Coffeyville, Kansas and El Dorado, Kansas for the transportation
of natural gas liquids (NGLs) and refined petroleum products.
Pursuant to this agreement, CRRM is obligated to make fixed
monthly lease payments. The agreement also obligates CRRM to
reimburse MAPL a portion of certain permitted costs associated
with obligations imposed by certain governmental laws. Lease
expense associated with this agreement, included in cost of
product sold (exclusive of depreciation and amortization) for
the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007, totaled
approximately $156,000, $208,000, $800,000, and $800,000,
respectively. The lease expires September 30, 2011.
During 2005, CRRM entered into a Pipeage Contract with MAPL
pursuant to which CRRM agreed to ship a minimum quantity of NGLs
on an inbound pipeline operated by MAPL between Conway, Kansas
and Coffeyville, Kansas. Pursuant to the contract, CRRM is
obligated to ship 2,000,000 barrels (Minimum Commitment) of
NGLs per year at a fixed rate per barrel through the expiration
of the contract on September 30, 2011. All barrels above
the Minimum Commitment are at a different fixed rate per barrel.
The rates are subject to a tariff approved by the Kansas
Corporation Commission (KCC) and are subject to change
throughout the term of this contract as ordered by the KCC.
Lease expense associated with this contract agreement and
included in cost of product sold (exclusive of depreciation and
amortization) for the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007, totaled
approximately $173,000, $1,613,000, and $1,400,000, respectively.
During 2004, CRRM entered into a Pipeline Capacity Lease
Agreement with ONEOK Field Services (OFS) and Frontier El Dorado
Refining Company (Frontier) pursuant to which CRRM leases
capacity in pipelines operated by OFS between Conway, Kansas and
El Dorado, Kansas. Prior to the completion of a planned
expansion project specified in the agreement, CRRM will be
obligated to pay a fixed monthly charge which will increase
after the expansion is complete. The lease expires
September 30, 2011. Lease expense associated with this
contract agreement and included in cost of product sold
(exclusive of depreciation and amortization) for the year ended
December 31, 2007 totaled approximately $444,000.
During 2004, CRRM entered into a Transportation Services
Agreement with CCPS Transportation, LLC (CCPS) pursuant to which
CCPS reconfigured an existing pipeline (Spearhead Pipeline) to
transport Canadian sourced crude oil to Cushing, Oklahoma. The
term of the agreement is 10 years from the time the
pipeline becomes operational, which occurred March 1, 2006.
Pursuant to the agreement and pursuant to options for increased
capacity which CRRM has exercised, CRRM is obligated to pay an
incentive tariff, which is a fixed rate per barrel for a minimum
of 10,000 barrels per day. Lease expense associated with
this agreement included in cost of product sold (exclusive of
depreciation and amortization) for the years ended
December 31, 2006 and December 31, 2007 totaled
approximately $4,609,000 and $6,980,000, respectively.
During 2004, CRRM entered into a Terminalling Agreement with
Plains Marketing, LP (Plains) whereby CRRM has the exclusive
storage rights for working storage, blending, and terminalling
services at several Plains tanks in Cushing, Oklahoma. During
2007, CRRM entered into an Amended
F-46
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
and Restated Terminalling Agreement with Plains that replaced
the 2004 agreement. Pursuant to the Amended and Restated
Terminalling Agreement, CRRM is obligated to pay fees on a
minimum throughput volume commitment of 29,200,000 barrels per
year. Fees are subject to change annually based on changes in
the Consumer Price Index (CPI-U) and the Producer Price Index
(PPI-NG). Expenses associated with this agreement, included in
cost of product sold (exclusive of depreciation and
amortization) for the 174-day period ended June 23, 2005,
the 233-day period ended December 31, 2005, and the years
ended December 31, 2006 and December 31, 2007, totaled
approximately $812,000, $1,251,000, $2,406,000, and $2,396,000,
respectively. The original term of the Amended and Restated
Terminalling Agreement expires December 31, 2014, but is
subject to annual automatic extensions of one year beginning two
years and one day following the effective date of the agreement,
and successively every year thereafter unless either party
elects not to extend the agreement. Concurrently with the
above-described Amended and Restated Terminalling Agreement,
CRRM entered into a separate Terminalling Agreement with Plains
whereby CRRM has obtained additional exclusive storage rights
for working storage and terminalling services at several Plains
tanks in Cushing, Oklahoma. CRRM is obligated to pay Plains fees
based on the storage capacity of the tanks involved, and such
fees are subject to change annually based on changes in the
Producer Price Index (PPI-FG and PPI-NG). The term of the
Terminalling Agreement is split up into two periods based on the
tanks at issue, with the term for half of the tanks commencing
once they are placed in service (but no later than
January 1, 2008), and the term for the remaining half of
the tanks commencing October 1, 2008. The original term of the
Terminalling Agreement for both sets of tanks expires
December 31, 2014, but is subject to annual automatic
extensions of one year beginning two years and one day following
the effective date of the agreement, and successively every year
thereafter unless either party elects not to extend the
agreement.
During 2005 CRNF entered into the Amended and Restated
On-Site
Product Supply Agreement with The Linde Group. Pursuant to the
agreement, which expires in 2020, CRNF is required to take as
available and pay approximately $300,000 per month, which amount
is subject to annual inflation adjustments, for the supply of
oxygen and nitrogen to the fertilizer operation. Expenses
associated with this agreement, included in direct operating
expenses (exclusive of depreciation and amortization) for the
years ended December 31, 2006 and December 31, 2007,
totaled approximately $3,521,000 and $3,136,000, respectively.
During 2006, CRRM entered into a Lease Storage Agreement with
TEPPCO Crude Pipeline, L.P. (TEPPCO) whereby CRRM leases
400,000 barrels of shell capacity at TEPPCOs Cushing
tank farm in Cushing, Oklahoma. In September 2006, CRRM
exercised its option to increase the shell capacity leased at
the facility subject to this agreement from 400,000 barrels
to 550,000 barrels. Pursuant to the agreement, CRRM is
obligated to pay a monthly per barrel fee regardless of the
number of barrels of crude oil actually stored at the leased
facilities. Expenses associated with this agreement included in
cost of product sold (exclusive of depreciation and
amortization) for the year ended December 31, 2007 totaled
approximately $1,110,000.
During 2006, CRCT entered into a Pipeline Lease Agreement with
Magellan whereby CRCT leases sixty-two miles of eight inch
pipeline extending from Humboldt, Kansas to CRCTs
facilities located in Broome, Kansas. Pursuant to the lease
agreement, CRCT agrees to operate and maintain the leased
pipeline and agrees to pay Magellan a fixed annual rental in
advance. Expenses associated with this agreement, included in
cost of product sold (exclusive of depreciation and
amortization) for the years ended December 31, 2006 and
December 31, 2007 totaled approximately $76,000 and
$183,000, respectively. Pursuant to an amendment entered into in
2007, the lease agreement expires on July 31, 2009 with, at
the Companys option, up to two one year extensions.
During 2006, CRRM entered into a Transfer Agreement with
Magellan pursuant to which CRRM obtained the right to capacity
in a pipeline operated by Magellan between Coffeyville, Kansas
and El
F-47
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Dorado, Kansas. Pursuant to the agreement, CRRM is obligated to
pay a fixed monthly charge for the right to transfer up to
1,000,000 barrels per year through the pipeline. The
initial term of the agreement expires on July 14, 2009;
however the agreement contains two successive one year
additional terms unless CRRM or Magellan provides termination
notice as required in the agreement. Expenses associated with
this agreement, included in cost of product sold (exclusive of
depreciation and amortization) for the year ended
December 31, 2007 totaled approximately $79,000.
During 2007, CRRM executed a Petroleum Transportation Service
Agreement with TransCanada Keystone Pipeline, LP (TransCanada).
TransCanada is proposing to construct, own and operate a
pipeline system and a related extension and expansion of the
capacity that would terminate near Cushing, Oklahoma.
TransCanada has agreed to transport a contracted volume amount
of at least 25,000 barrels per day with a Cushing Delivery
Point as the contract point of delivery. The contract term is a
10 year period which will commence upon the completion of
the pipeline system. The expected date of commencement is March
2010 with termination of the transportation agreement estimated
to be February 2020. The Company will pay a fixed and variable
toll rate beginning during the month of commencement.
CRNF entered into a sales agreement with Cominco Fertilizer
Partnership on November 20, 2007 to purchase equipment and
materials which comprise a nitric acid plant. CRNFs
obligation related to the execution of the agreement in 2007 for
the purchase of the assets was $3,500,000. As of
December 31, 2007, $250,000 had been paid with $3,250,000
remaining as an accrued current obligation. Additionally,
$3,000,000 was accrued related to the obligation to dismantle
the unit. These amounts incurred are included in
construction-in-progress
at December 31, 2007. The total unpaid obligation at
December 31, 2007 of $6,250,000 is included in other
current liabilities on the Consolidated Balance Sheet.
As a result of the adoption of FIN 47 in 2005, CVR recorded
a net asset retirement obligation of $636,000 which was included
in other current liabilities at December 31, 2006 and
December 31, 2007.
From time to time, CVR is involved in various lawsuits arising
in the normal course of business, including matters such as
those described below under, Environmental, Health, and
Safety Matters, and those described above. Liabilities
related to such litigation are recognized when the related costs
are probable and can be reasonably estimated. Management
believes the company has accrued for losses for which it may
ultimately be responsible. It is possible managements
estimates of the outcomes will change within the next year due
to uncertainties inherent in litigation and settlement
negotiations. In the opinion of management, the ultimate
resolution of any other litigation matters is not expected to
have a material adverse effect on the accompanying consolidated
financial statements.
Crude oil was discharged from the Companys refinery on
July 1, 2007 due to the short amount of time available to
shut down and secure the refinery in preparation for the flood
that occurred on June 30, 2007. As a result of the crude
oil discharge, two putative class action lawsuits (one federal
and one state) were filed seeking unspecified damages with class
certification under applicable law for all residents,
domiciliaries and property owners of Coffeyville, Kansas who
were impacted by the oil release.
The Company filed a motion to dismiss the federal suit for lack
of subject matter jurisdiction. On November 6, 2007, the
judge in the federal class action lawsuit granted the
Companys motion to dismiss for lack of subject matter
jurisdiction and no appeal was taken.
The District Court of Montgomery County, Kansas conducted an
evidentiary hearing on the issue of class certification on
October 24 and 25, 2007 and ruled against the class
certification leaving only the original two plaintiffs. To date
no other lawsuits have been filed as a result of flood related
damages.
As a result of the crude oil discharge that occurred on
July 1, 2007, the Company entered into an administrative
order on consent (the Consent Order) with the EPA on
July 10, 2007. As set forth in
F-48
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
the Consent Order, the EPA concluded that the discharge of oil
from the Companys refinery caused and may continue to
cause an imminent and substantial threat to the public health
and welfare. Pursuant to the Consent Order, the Company agreed
to perform specified remedial actions to respond to the
discharge of crude oil from the Companys refinery. The
Company is currently remediating the crude oil discharge and
expects its remedial actions to continue until May 2008.
The Company engaged experts to assess and test the areas
affected by the crude oil spill. The Company commenced a program
on July 19, 2007 to purchase approximately 330 homes and
other commercial properties in connection with the flood and the
crude oil release. The costs recorded as of December 31,
2007 related to the obligation of the homes being purchased,
were approximately $13.1 million, and are included in
Net Costs Associated With Flood in the accompanying
consolidated statement of operations. Costs recorded related to
personal property claims were approximately $1.7 million as
of December 31, 2007. The costs recorded related to
estimated commercial property to be purchased and associated
claims were approximately $3.6 million as of
December 31, 2007. The total amount of gross costs recorded
for the twelve months ended December 31, 2007 related to
the residential and commercial purchase and property claims
program were approximately $18.4 million.
As of December 31, 2007, the total gross costs recorded for
obligations other than the purchase of homes, commercial
properties, and related personal property claims, approximated
$26.5 million. The Company has recorded as of
December 31, 2007, total costs (net of anticipated
insurance recoveries recorded of $21.4 million) associated
with remediation and third party property damage claims
resolution of approximately $23.5 million. The Company has
not estimated or accrued for, because management does not
believe it is probable that there will be any, potential fines,
penalties or claims that may be imposed or brought by regulatory
authorities or possible additional damages arising from class
action lawsuits related to the flood.
It is difficult to estimate the ultimate cost of environmental
remediation resulting from the crude oil discharge or the cost
of third party property damage that the Company will ultimately
be required to pay. The costs and damages that the Company will
ultimately pay may be greater than the amounts described and
projected above. Such excess costs and damages could be material
to the consolidated financial statements.
The Company is seeking insurance coverage for this release and
for the ultimate costs for remediation, property damage claims,
cleanup, resolution of class action lawsuits, and other claims
brought by regulatory authorities. Although the Company believes
that it will recover substantial sums under its environmental
and liability insurance policies, the Company is not sure of the
ultimate amount or timing of such recovery because of the
difficulty inherent in projecting the ultimate resolution of the
Companys claims. The difference between what the Company
receives under its insurance policies compared to what has been
recorded and described above could be material to the
consolidated financial statements. The Company has received
$10 million of insurance proceeds under its environmental
insurance policy as of December 31, 2007.
As a result of the 2007 flood the refinery was not able to meet
the annual average sulfur standard required in its
hardship waiver. Management had provided timely
notice to the EPA that the Company would not be able to meet the
waiver requirement for 2007. Ordinarily, a refiner would
purchase sulfur credits to meet the standard requirement.
However, the Companys hardship waiver does not
allow sulfur credits to be used in 2006 and 2007. The Company
has been working with the EPA to resolve the matter. In
anticipation of settlement, the refinery purchased
$3.6 million worth of sulfur credits that would equal the
amount of sulfur by which the Company exceeded the limit imposed
by the hardship waiver. The Company will either use
the credits by applying them towards its gasoline pool account
or it will permanently retire the credits as part of the
settlement. Because of the extraordinary nature of the 2007
flood, management does not anticipate the imposition of fines or
penalties to resolve this matter.
F-49
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Environmental,
Health, and Safety (EHS) Matters
CVR is subject to various stringent federal, state, and local
EHS rules and regulations. Liabilities related to EHS matters
are recognized when the related costs are probable and can be
reasonably estimated. Estimates of these costs are based upon
currently available facts, existing technology, site-specific
costs, and currently enacted laws and regulations. In reporting
EHS liabilities, no offset is made for potential recoveries.
Such liabilities include estimates of CVRs share of costs
attributable to potentially responsible parties which are
insolvent or otherwise unable to pay. All liabilities are
monitored and adjusted regularly as new facts emerge or changes
in law or technology occur.
CVR owns
and/or
operates manufacturing and ancillary operations at various
locations directly related to petroleum refining and
distribution and nitrogen fertilizer manufacturing. Therefore,
CVR has exposure to potential EHS liabilities related to past
and present EHS conditions at some of these locations.
Through an Administrative Order issued to Original Predecessor
under the Resource Conservation and Recovery Act, as amended
(RCRA), CVR is a potential party responsible for conducting
corrective actions at its Coffeyville, Kansas and Phillipsburg,
Kansas facilities. In 2005, CRNF agreed to participate in the
State of Kansas Voluntary Cleanup and Property Redevelopment
Program (VCPRP) to address a reported release of urea ammonium
nitrate (UAN) at the Coffeyville UAN loading rack. As of
December 31, 2006 and December 31, 2007, environmental
accruals of $7,223,000 and $7,646,000, respectively, were
reflected in the consolidated balance sheets for probable and
estimated costs for remediation of environmental contamination
under the RCRA Administrative Order and the VCPRP, including
amounts totaling $1,828,000 and $2,802,000, respectively,
included in other current liabilities. The Successor accruals
were determined based on an estimate of payment costs through
2033, which scope of remediation was arranged with the EPA and
are discounted at the appropriate risk free rates at
December 31, 2006 and December 31, 2007, respectively.
The accruals include estimated closure and post-closure costs of
$1,857,000 and $1,549,000 for two landfills at December 31,
2006 and December 31, 2007, respectively. The estimated
future payments for these required obligations are as follows
(in thousands):
|
|
|
|
|
Year Ending December
31,
|
|
Amount
|
|
|
2008
|
|
$
|
2,802
|
|
2009
|
|
|
687
|
|
2010
|
|
|
1,556
|
|
2011
|
|
|
313
|
|
2012
|
|
|
313
|
|
Thereafter
|
|
|
3,282
|
|
|
|
|
|
|
Undiscounted total
|
|
|
8,953
|
|
Less amounts representing interest at 3.90%
|
|
|
1,307
|
|
|
|
|
|
|
Accrued environmental liabilities at December 31, 2007
|
|
$
|
7,646
|
|
|
|
|
|
|
Management periodically reviews and, as appropriate, revises its
environmental accruals. Based on current information and
regulatory requirements, management believes that the accruals
established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of
sulfur in diesel and gasoline. The EPA has granted petition for
a technical hardship waiver with respect to the date for
compliance in meeting the sulfur-lowering standards. Immediate
Predecessor and Successor spent approximately $27 million
in 2005, $79 million in 2006, and $17 million in 2007,
and based on information currently available, CVR anticipates
spending approximately $29 million in 2008,
$11 million in 2009, and
F-50
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
$6 million in 2010 to comply with the low-sulfur rules. The
entire amounts are expected to be capitalized.
Environmental expenditures are capitalized when such
expenditures are expected to result in future economic benefits.
For the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006 and December 31, 2007 capital
expenditures were approximately $6,066,000, $20,165,000,
$144,794,000, and $122,341,000, respectively, and were incurred
to improve the environmental compliance and efficiency of the
operations.
CVR believes it is in substantial compliance with existing EHS
rules and regulations. There can be no assurance that the EHS
matters described above or other EHS matters which may develop
in the future will not have a material adverse effect on the
business, financial condition, or results of operations.
|
|
(16)
|
Derivative
Financial Instruments
|
Gain (loss) on derivatives consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Successor
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
|
Ended June 23,
|
|
|
|
Ended December 31,
|
|
|
Ended December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
Realized loss on swap agreements
|
|
$
|
|
|
|
|
$
|
(59,301
|
)
|
|
$
|
(46,769
|
)
|
|
$
|
(157,239
|
)
|
Unrealized gain (loss) on swap agreements
|
|
|
|
|
|
|
|
(235,852
|
)
|
|
|
126,771
|
|
|
|
(103,212
|
)
|
Loss on termination of swap
|
|
|
|
|
|
|
|
(25,000
|
)
|
|
|
|
|
|
|
|
|
Realized gain (loss) on other agreements
|
|
|
(7,665
|
)
|
|
|
|
(1,868
|
)
|
|
|
8,361
|
|
|
|
(15,346
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
|
|
|
|
|
(1,696
|
)
|
|
|
2,412
|
|
|
|
(1,348
|
)
|
Realized gain (loss) on interest rate swap agreements
|
|
|
|
|
|
|
|
(104
|
)
|
|
|
4,398
|
|
|
|
4,115
|
|
Unrealized gain (loss) on interest rate swap agreements
|
|
|
|
|
|
|
|
7,759
|
|
|
|
(680
|
)
|
|
|
(8,948
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives
|
|
$
|
(7,665
|
)
|
|
|
$
|
(316,062
|
)
|
|
$
|
94,493
|
|
|
$
|
(281,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CVR is subject to price fluctuations caused by supply
conditions, weather, economic conditions, and other factors and
to interest rate fluctuations. To manage price risk on crude oil
and other inventories and to fix margins on certain future
production, the Company may enter into various derivative
transactions. In addition, the Successor, as further described
below, entered into certain commodity derivate contracts and an
interest rate swap as required by the long-term debt agreements.
CVR has adopted SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities
which imposes
extensive record-keeping requirements in order to designate a
derivative financial instrument as a hedge. CVR holds derivative
instruments, such as exchange-traded crude oil futures, certain
over-the-counter forward swap agreements, and interest rate swap
agreements, which it believes provide an economic hedge on
future transactions, but such instruments are not designated as
hedges. Gains or losses related to the change in fair value and
periodic settlements of these derivative instruments are
classified as gain (loss) on derivatives.
F-51
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
At December 31, 2007, CVRs Petroleum Segment held
commodity derivative contracts (swap agreements) for the period
from July 1, 2005 to June 30, 2010 with a related
party (see Note 17). The swap agreements were originally
executed on June 16, 2005 in conjunction with the
Acquisition of the Immediate Predecessor and required under the
terms of the long-term debt agreements. The notional quantities
on the date of execution were 100,911,000 barrels of crude
oil; 2,348,802,750 gallons of unleaded gasoline and
1,889,459,250 gallons of heating oil. The swap agreements were
executed at the prevailing market rate at the time of execution
and Management believes the swap agreements provide an economic
hedge on future transactions. At December 31, 2007 the
notional open amounts under the swap agreements were
42,309,750 barrels of crude oil; 888,504,750 gallons of
unleaded gasoline and 888,504,750 gallons of heating oil. These
positions resulted in unrealized gains (losses) for the
233-day
period ended December 31, 2005 and the years ended
December 31, 2006 and December 31, 2007 of
$(235,852,000), $126,771,000 and $(103,212,000), respectively,
using a valuation method that utilizes quoted market prices and
assumptions for the estimated forward yield curves of the
related commodities in periods when quoted market prices are
unavailable. The Petroleum Segment recorded $(59,301,000),
$(46,769,000) and $(157,239,000) in realized (losses) on these
swap agreements for the 233-day period ended December 31,
2005, and the years ended December 31, 2006 and
December 31, 2007, respectively.
Successor entered certain crude oil, heating oil, and gasoline
option agreements with a related party (see Notes 1 and
17) as of May 16, 2005. These agreements expired
unexercised on June 16, 2005 and resulted in an expense of
$25,000,000 reported in the accompanying consolidated statements
of operations as gain (loss) on derivatives for the
233 days ended December 31, 2005.
The Petroleum Segment also recorded mark-to-market net gains
(losses), exclusive of the swap agreements described above and
the interest rate swaps described in the following paragraph, in
gain (loss) on derivatives of $(7,665,000), $(3,564,000),
$10,773,000, and $(16,694,000) for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, the years ended
December 31, 2006, and December 31, 2007,
respectively. All of the activity related to the commodity
derivative contracts is reported in the Petroleum Segment.
At December 31, 2007, CVR held derivative contracts known
as interest rate swap agreements that converted Successors
floating-rate bank debt (see Note 12) into 4.195%
fixed-rate debt on a notional amount of $375,000,000. Half of
the agreements are held with a related party (as described in
Note 17), and the other half are held with a financial
institution that is a lender under CVRs long-term debt
agreements. The swap agreements carry the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Fixed
|
|
Period Covered
|
|
Amount
|
|
|
Interest Rate
|
|
|
June 30, 2007 to March 31, 2008
|
|
|
325 million
|
|
|
|
4.195
|
%
|
March 31, 2008 to March 31, 2009
|
|
|
250 million
|
|
|
|
4.195
|
%
|
March 31, 2009 to March 31, 2010
|
|
|
180 million
|
|
|
|
4.195
|
%
|
March 31, 2010 to June 30, 2010
|
|
|
110 million
|
|
|
|
4.195
|
%
|
CVR pays the fixed rates listed above and receives a floating
rate based on three-month LIBOR rates, with payments calculated
on the notional amounts listed above. The notional amounts do
not represent actual amounts exchanged by the parties but
instead represent the amounts on which the contracts are based.
The swap is settled quarterly and marked to market at each
reporting date, and all unrealized gains and losses are
currently recognized in income. Transactions related to the
interest rate swap agreements were not allocated to the
Petroleum or Nitrogen Fertilizer segments. Mark-to-market net
gains (losses) on derivatives and quarterly settlements were
$7,655,000, $3,718,000 and $(4,833,000) for the
233-day
period ended December 31, 2005 and the years ended
December 31, 2006 and December 31, 2007, respectively.
F-52
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(17)
|
Related Party
Transactions
|
Pegasus Partners II, L.P. (Pegasus) was a majority owner of
Immediate Predecessor.
On March 3, 2004, Immediate Predecessor entered into a
services agreement with an affiliate company of Pegasus, Pegasus
Capital Advisors, L.P. (Affiliate) pursuant to which Affiliate
provided Immediate Predecessor with managerial and advisory
services. An amount totaling approximately $1,000,000 relating
to the agreement were expensed in selling, general, and
administrative expenses (exclusive of depreciation and
amortization) for the 174 days ended June 23, 2005.
GS Capital Partners V Fund, L.P. and related entities (GS or
Goldman Sachs Funds) and Kelso Investment Associates VII, L.P.
and related entity (Kelso or Kelso Funds) are majority owners of
CVR.
CVR paid companies related to GS and Kelso each equal amounts
totaling $6.0 million for transaction fees related to the
Acquisition, as well as an additional $0.7 million paid to
GS for reimbursed expenses related to the Acquisition. These
expenditures were included in the cost of the Acquisition
referred to in Note 1.
An affiliate of GS is one of the lenders in conjunction with the
financing of the Acquisition. The Company paid this affiliate of
GS a $22.1 million fee included in deferred financing
costs. For the 233 days ended December 31, 2005,
Successor made interest payments of $1.8 million recorded
in interest expense and other financial costs and paid letter of
credit fees of approximately $155,000 recorded in selling,
general, and administrative expenses (exclusive of depreciation
and amortization), to this affiliate of GS. Additionally, a fee
in the amount of $125,000 was paid to this affiliate of GS for
assistance with modification of the credit facility in June 2006.
An affiliate of GS is one of the lenders in conjunction with the
refinancing that occurred on December 28, 2006. The Company
paid this affiliate of GS a $8,063,000 million fee and
expense reimbursements of $78,000 included in deferred financing
costs.
On June 24, 2005, CALLC entered into management services
agreements with each of GS and Kelso pursuant to which GS and
Kelso agreed to provide CALLC with managerial and advisory
services. In consideration for these services, an annual fee of
$1.0 million each was paid to GS and Kelso, plus
reimbursement for any out-of-pocket expenses. The agreements had
a term ending on the date GS and Kelso ceased to own any
interests in CALLC. Relating to the agreements, $1,310,000,
$2,316,000 and $1,704,000 were expensed in selling, general, and
administrative expenses (exclusive of depreciation and
amortization) for the 233 days ended December 31,
2005, and the years ended December 31, 2006 and
December 31, 2007, respectively. The agreements terminated
upon consummation of CVRs initial public offering on
October 26, 2007. The Company paid a one-time fee of
$5 million to each of GS and Kelso by reason of such
termination on October 26, 2007.
CALLC entered into certain crude oil, heating oil, and gasoline
swap agreements with a subsidiary of GS. The original swap
agreements were entered into on May 16, 2005 (as described
in note 1) and were terminated on June 16, 2005,
resulting in a $25 million loss on termination of swap
agreements for the 233 days ended December 31, 2005.
Additional swap agreements with this subsidiary of GS were
entered into on June 16, 2005, with an expiration date of
June 30, 2010 (as described in Note 16). Amounts
totaling $(297,011,000), $80,002,000, and $(260,451,000) were
reflected in gain (loss) on derivatives related to these swap
agreements for the 233 days ended December 31, 2005,
and the years ended December 31, 2006 and December 31,
2007, respectively. In addition, the consolidated balance sheet
at December 31, 2006 and December 31, 2007 includes
liabilities of $36,895,000 and $262,415,000 included in current
payable to swap counterparty and $72,806,000 and $88,230,000
included in long-term payable to swap counterparty, respectively.
On June 26, 2007, the Company entered into a letter
agreement with the subsidiary of GS to defer a
$45.0 million payment owed on July 8, 2007 to the GS
subsidiary for the period ended
F-53
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
September 30, 2007 until August 7, 2007. Interest
accrued on the deferred amount of $45.0 million at the rate
of LIBOR plus 3.25%.
As a result of the flood and the related temporary cessation of
business operations, the Company entered into a subsequent
letter agreement on July 11, 2007 in which the GS
subsidiary agreed to defer an additional $43.7 million of the
balance owed for the period ending June 30, 2007. This
deferral was entered into on the conditions that each of GS and
Kelso each agreed to guarantee one half of the payment and that
interest accrued on the $43.7 million from July 9,
2007 to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter
agreement in which the GS subsidiary agreed to defer to
September 7, 2007 both the $45.0 million payment due
August 7, 2007 along with accrued interest and the
$43.7 million payment due July 25, 2007 with the
related accrued interest. These payments were deferred on the
conditions that GS and Kelso each agreed to guarantee one half
of the payments. Additionally, interest accrues on the amount
from July 26, 2007 to the date of payment at the rate of
LIBOR plus 1.50%.
On August 23, 2007, the Company entered into an additional
letter agreement in which the GS subsidiary agreed to further
defer both deferred payment amounts and the related accrued
interest with payment being due on January 31, 2008.
Additionally, it was further agreed that the $35 million
payment to settle hedged volumes through August 15, 2007
would be deferred with payment being due on January 31,
2008. Interest accrues on all deferral amounts through the
payment due date at LIBOR plus 1.50%. GS and Kelso have each
agreed to guarantee one half of all payment deferrals. The GS
Subsidiary further agreed to defer these payment amounts to
August 31, 2008 if the Company closed an initial public
offering prior to January 31, 2008. Due to the consummation
of the initial public offering on October 26, 2007, these
payment amounts are now deferred until August 31, 2008;
however, the company is required to use 37.5% of its
consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferral amounts.
These deferred payment amounts are included in the consolidated
balance sheet at December 31, 2007 in current payable to
swap counterparty. Interest relating to the deferred payment
amounts reflected in interest expense and other financial costs
for the year ended December 31, 2007 was $3,625,000.
$3,625,000 is also included in other current liabilities at
December 31, 2007.
On June 30, 2005, CVR entered into three interest-rate swap
agreements with the same subsidiary of GS (as described in
Note 16). Amounts totaling $3,826,000, $1,858,000, and
$(2,405,000) were recognized related to these swap agreements
for the 233 days ended December 31, 2005, and the
years ended December 31, 2006 and December 31, 2007,
respectively, and are reflected in gain (loss) on derivatives.
In addition, the consolidated balance sheet at December 31,
2006 and December 31, 2007 includes $1,534,000 and $0 in
prepaid expenses and other current assets, $2,015,000 and $0 in
other long-term assets, $0 and $371,000 in other current
liabilities and $0 and $557,000 in other long-term liabilities
related to the same agreements, respectively.
Effective December 30, 2005, CVR entered into a crude oil
supply agreement with a subsidiary of GS (Supplier). Both
parties will negotiate the cost of each barrel of crude oil to
be purchased from a third party. CVR will pay Supplier a fixed
supply service fee per barrel over the negotiated cost of each
barrel of crude purchased. The cost is adjusted further using a
spread adjustment calculation based on the time period the crude
oil is estimated to be delivered to the refinery, other market
conditions, and other factors deemed appropriate. The monthly
spread quantity for any delivery month at any time shall not
exceed approximately 3.1 million barrels. The initial term
of the agreement was to December 31, 2006. CVR and Supplier
agreed to extend the term of the Supply Agreement for an
additional 12 month period, January 1, 2007 through
December 31, 2007 and in connection with the extension
amended certain terms and conditions of the Supply Agreement. On
December 31, 2007,
F-54
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
CVR and supplier entered into an amended and restated crude oil
supply agreement. The terms of the agreement remained
substantially the same. $1,623,000 and $360,000 were recorded on
the consolidated balance sheet at December 31, 2006 and
December 31, 2007, respectively, in prepaid expenses and
other current assets for prepayment of crude oil. In addition,
$31,751,000 and $43,773,000 were recorded in inventory and
$13,459,000 and $42,666,000 were recorded in accounts payable at
December 31, 2006 and December 31, 2007, respectively.
Expenses associated with this agreement, included in cost of
product sold (exclusive of depreciated and amortization) for the
years ended December 31, 2006 and December 31, 2007
totaled $1,591,120,000 and $1,476,811,000 respectively. Interest
expense associated with this agreement for the years ended
December 31, 2006 and December 31, 2007 totaled $0 and
$(376,000), respectively.
The Company had a note receivable with an executive member of
management. During the period ended December 31, 2006, the
board of directors approved to forgive the note receivable and
related accrued interest receivable. The balance of the note
receivable forgiven was $350,000. Accrued interest receivable
forgiven was approximately $18,000. The total amount was charged
to compensation expense.
On August 23, 2007, the Company entered into three new
credit facilities, consisting of a $25 million secured
facility, a $25 million unsecured facility and a
$75 million unsecured facility. A subsidiary of GS was the
sole lead arranger and sole bookrunner for each of these new
credit facilities. These credit facilities and their
arrangements are more fully described in Note 12,
Long-Term Debt. The Company paid the subsidiary of
GS a $1.3 million fee included in deferred financing costs.
For the year ended December 31, 2007, interest expenses
relating to these agreements were $867,000. The secured and
unsecured facilities were paid in full on October 26, 2007
with proceeds from CVRs initial public offering, see
Note 1, Organization and History of Company,
and both facilities terminated. Additionally, in connection with
the consummation of the initial public offering, the
$75 million unsecured facility also terminated.
As a result of the refinery turnaround in early 2007, CVR needed
to delay the processing of quantities of crude oil that it
purchased from various small independent producers. In order to
facilitate this anticipated delay, CVR entered into a purchase,
storage and sale agreement for gathered crude oil, dated
March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant
to the terms of the agreement, J. Aron agreed to purchase
gathered crude oil from CVR, store the gathered crude oil and
sell CVR the gathered crude oil on a forward basis. As of
December 31, 2007, there were no longer any open
commitments with regard to the agreement. Interest expense
associated with this agreement included in interest expense and
other financing costs was $196,000.
Goldman, Sachs & Co. was the lead underwriter of
CVRs initial public offering in October 2007. As lead
underwriter, they were paid a customary underwriting discount of
approximately $14.7 million, which includes
$0.7 million of expense reimbursement.
On October 24, 2007, CVR paid a cash dividend, to its
shareholders, including approximately $5.23 million that
was ultimately distributed from CALLC II (Goldman Sachs Funds)
and approximately $5.15 million distributed from CALLC to
the Kelso Funds. Management collectively received approximately
$0.13 million.
CVR measures segment profit as operating income for Petroleum
and Nitrogen Fertilizer, CVRs two reporting segments,
based on the definitions provided in SFAS No. 131,
Disclosures About Segments of an Enterprise and Related
Information
. All operations of the segments are located in
the United States.
F-55
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
CVR changed its corporate selling, general and administrative
allocation method to the operating segments in 2007. The effect
of the change on operating income for
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005 and the year ended
December 31, 2006 would have been a decrease of
$1.0 million, $1.4 million and $6.0 million,
respectively, to the petroleum segment, an increase of
$1.2 million, $1.4 million and $6.0 million,
respectively, to the nitrogen fertilizer segment and a decrease
of $0.2 million, $0.0 million and $0.0 million,
respectively, to the other segment.
Petroleum
Principal products of the Petroleum Segment are refined fuels,
propane, and petroleum refining by-products including coke. CVR
uses the coke in the manufacture of nitrogen fertilizer at the
adjacent nitrogen fertilizer plant. (For CVR, a $15-per-ton
transfer price is used to record intercompany sales on the part
of the Petroleum Segment and corresponding intercompany cost of
product sold (exclusive of depreciation and amortization) for
the Nitrogen Fertilizer Segment through October 24, 2007.)
After October 24, 2007, intercompany sales are recorded
according to the interconnect agreement (see Note 1). The
intercompany transactions are eliminated in the Other Segment.
Intercompany sales included in Petroleum net sales were
$2,445,000, $2,782,000, $5,340,000, and $5,195,000 for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007, respectively.
Nitrogen
Fertilizer
The principal product of the Nitrogen Fertilizer Segment is
nitrogen fertilizer. Intercompany cost of product sold
(exclusive of depreciation and amortization) for the coke
transfer described above was $2,778,000, $2,575,000, $5,242,000,
and $4,528,000 for the
174-day
period ended June 23, 2005, the
233-day
period ended December 31, 2005, and the years ended
December 31, 2006, and December 31, 2007, respectively.
F-56
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Other
Segment
The Other Segment reflects intercompany eliminations, cash and
cash equivalents, all debt related activities, income tax
activities and other corporate activities that are not allocated
to the operating segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
|
(in thousands)
|
|
Net sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
903,803
|
|
|
|
$
|
1,363,390
|
|
|
$
|
2,880,442
|
|
Nitrogen Fertilizer
|
|
|
79,348
|
|
|
|
|
93,652
|
|
|
|
162,465
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment elimination
|
|
|
(2,445
|
)
|
|
|
|
(2,782
|
)
|
|
|
(5,340
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
980,706
|
|
|
|
$
|
1,454,260
|
|
|
$
|
3,037,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
761,719
|
|
|
|
$
|
1,156,208
|
|
|
$
|
2,422,718
|
|
Nitrogen Fertilizer
|
|
|
9,126
|
|
|
|
|
14,504
|
|
|
|
25,898
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment elimination
|
|
|
(2,778
|
)
|
|
|
|
(2,575
|
)
|
|
|
(5,242
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
768,067
|
|
|
|
$
|
1,168,137
|
|
|
$
|
2,443,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
52,611
|
|
|
|
$
|
56,159
|
|
|
$
|
135,297
|
|
Nitrogen Fertilizer
|
|
$
|
28,303
|
|
|
|
|
29,154
|
|
|
|
63,683
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
80,914
|
|
|
|
$
|
85,313
|
|
|
$
|
198,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
771
|
|
|
|
$
|
15,567
|
|
|
$
|
33,017
|
|
Nitrogen Fertilizer
|
|
|
316
|
|
|
|
|
8,361
|
|
|
|
17,126
|
|
Other
|
|
|
41
|
|
|
|
|
26
|
|
|
|
862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,128
|
|
|
|
$
|
23,954
|
|
|
$
|
51,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
76,654
|
|
|
|
$
|
123,045
|
|
|
$
|
245,578
|
|
Nitrogen Fertilizer
|
|
|
35,268
|
|
|
|
|
35,731
|
|
|
|
36,842
|
|
Other
|
|
|
333
|
|
|
|
|
(240
|
)
|
|
|
(812
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
112,255
|
|
|
|
$
|
158,536
|
|
|
$
|
281,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-57
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
|
(in thousands)
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
10,790
|
|
|
|
$
|
42,108
|
|
|
$
|
223,552
|
|
Nitrogen fertilizer
|
|
|
1,435
|
|
|
|
|
2,017
|
|
|
|
13,258
|
|
Other
|
|
|
32
|
|
|
|
|
1,047
|
|
|
|
3,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
12,257
|
|
|
|
$
|
45,172
|
|
|
$
|
240,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
|
|
|
|
|
|
|
|
|
$
|
907,315
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
|
|
|
|
|
417,657
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
124,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
$
|
1,449,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
|
|
|
|
|
|
|
|
|
$
|
42,806
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
|
|
|
|
|
40,969
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
$
|
83,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustment
|
|
|
As Restated()
|
|
|
|
(in thousands)
|
|
Net sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
2,806,205
|
|
|
$
|
|
|
|
$
|
2,806,205
|
|
Nitrogen Fertilizer
|
|
|
165,855
|
|
|
|
|
|
|
|
165,855
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment elimination
|
|
|
(5,195
|
)
|
|
|
|
|
|
|
(5,195
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,966,865
|
|
|
$
|
|
|
|
$
|
2,966,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
2,282,555
|
|
|
$
|
17,671
|
|
|
$
|
2,300,226
|
|
Nitrogen Fertilizer
|
|
|
13,042
|
|
|
|
|
|
|
|
13,042
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment elimination
|
|
|
(4,528
|
)
|
|
|
|
|
|
|
(4,528
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,291,069
|
|
|
$
|
17,671
|
|
|
$
|
2,308,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-58
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustment
|
|
|
As Restated()
|
|
|
|
(in thousands)
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
209,475
|
|
|
$
|
|
|
|
$
|
209,475
|
|
Nitrogen Fertilizer
|
|
|
66,663
|
|
|
|
|
|
|
|
66,663
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
276,138
|
|
|
$
|
|
|
|
$
|
276,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
36,669
|
|
|
$
|
|
|
|
$
|
36,669
|
|
Nitrogen Fertilizer
|
|
|
2,432
|
|
|
|
|
|
|
|
2,432
|
|
Other
|
|
|
2,422
|
|
|
|
|
|
|
|
2,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
41,523
|
|
|
$
|
|
|
|
$
|
41,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
43,040
|
|
|
$
|
|
|
|
$
|
43,040
|
|
Nitrogen Fertilizer
|
|
|
16,819
|
|
|
|
|
|
|
|
16,819
|
|
Other
|
|
|
920
|
|
|
|
|
|
|
|
920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
60,779
|
|
|
$
|
|
|
|
$
|
60,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
162,547
|
|
|
$
|
(17,671
|
)
|
|
$
|
144,876
|
|
Nitrogen Fertilizer
|
|
|
46,593
|
|
|
|
|
|
|
|
46,593
|
|
Other
|
|
|
(4,906
|
)
|
|
|
|
|
|
|
(4,906
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
204,234
|
|
|
$
|
(17,671
|
)
|
|
$
|
186,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
261,562
|
|
|
$
|
|
|
|
$
|
261,562
|
|
Nitrogen Fertilizer
|
|
|
6,488
|
|
|
|
|
|
|
|
6,488
|
|
Other
|
|
|
543
|
|
|
|
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
268,593
|
|
|
$
|
|
|
|
$
|
268,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,271,712
|
|
|
$
|
5,412
|
|
|
$
|
1,277,124
|
|
Nitrogen Fertilizer
|
|
|
446,763
|
|
|
|
|
|
|
|
446,763
|
|
Other
|
|
|
137,593
|
|
|
|
6,876
|
|
|
|
144,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,856,068
|
|
|
$
|
12,288
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
42,806
|
|
|
$
|
|
|
|
$
|
42,806
|
|
Nitrogen Fertilizer
|
|
|
40,969
|
|
|
|
|
|
|
|
40,969
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
83,775
|
|
|
$
|
|
|
|
$
|
83,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated
financial statements.
|
F-59
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(19)
|
Major Customers
and Suppliers
|
Sales to major customers were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
Petroleum
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer A
|
|
|
17
|
%
|
|
|
|
16
|
%
|
|
|
2
|
%
|
|
|
3
|
%
|
Customer B
|
|
|
5
|
%
|
|
|
|
6
|
%
|
|
|
5
|
%
|
|
|
5
|
%
|
Customer C
|
|
|
17
|
%
|
|
|
|
15
|
%
|
|
|
15
|
%
|
|
|
12
|
%
|
Customer D
|
|
|
14
|
%
|
|
|
|
17
|
%
|
|
|
10
|
%
|
|
|
7
|
%
|
Customer E
|
|
|
11
|
%
|
|
|
|
11
|
%
|
|
|
10
|
%
|
|
|
9
|
%
|
Customer F
|
|
|
8
|
%
|
|
|
|
7
|
%
|
|
|
9
|
%
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
|
%
|
|
|
|
72
|
%
|
|
|
51
|
%
|
|
|
46
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer G
|
|
|
16
|
%
|
|
|
|
10
|
%
|
|
|
5
|
%
|
|
|
3
|
%
|
Customer H
|
|
|
9
|
%
|
|
|
|
10
|
%
|
|
|
7
|
%
|
|
|
18
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
%
|
|
|
|
20
|
%
|
|
|
12
|
%
|
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Petroleum Segment maintains long-term contracts with one
supplier for the purchase of its crude oil. The agreement with
Supplier A expired in December 2005, at which time Successor
entered into a similar arrangement with Supplier B, a related
party (as described in Note 17). Purchases contracted as a
percentage of the total cost of product sold (exclusive of
depreciation and amortization) for each of the periods were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As restated()
|
|
Supplier A
|
|
|
82
|
%
|
|
|
|
73
|
%
|
|
|
|
|
|
|
|
|
Supplier B
|
|
|
|
|
|
|
|
|
|
|
|
67
|
%
|
|
|
63
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
|
%
|
|
|
|
73
|
%
|
|
|
67
|
%
|
|
|
63
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
()
|
|
See Note 2 to consolidated financial statements.
|
The Nitrogen Fertilizer Segment maintains long-term contracts
with one supplier. Purchases from this supplier as a percentage
of direct operating expenses (exclusive of depreciation and
amortization) were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174 Days
|
|
|
|
233 Days
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
Supplier
|
|
|
4
|
%
|
|
|
|
5
|
%
|
|
|
8
|
%
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-60
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
(20)
|
Selected
Quarterly Financial and Information (Unaudited)
|
Summarized quarterly financial data for the December 31,
2006 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
Quarter
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
(in thousands except share amounts)
|
|
|
|
|
|
Net sales
|
|
$
|
669,727
|
|
|
$
|
880,839
|
|
|
$
|
778,587
|
|
|
$
|
708,414
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
539,539
|
|
|
|
663,910
|
|
|
|
644,627
|
|
|
|
595,298
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
44,288
|
|
|
|
43,478
|
|
|
|
56,696
|
|
|
|
54,518
|
|
|
|
|
|
Selling, general and administrative (exclusive of depreciation
and amortization)
|
|
|
8,493
|
|
|
|
11,976
|
|
|
|
12,327
|
|
|
|
29,804
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
12,004
|
|
|
|
12,018
|
|
|
|
12,788
|
|
|
|
14,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
604,324
|
|
|
|
731,382
|
|
|
|
726,438
|
|
|
|
693,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
65,403
|
|
|
|
149,457
|
|
|
|
52,149
|
|
|
|
14,599
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(12,207
|
)
|
|
|
(10,129
|
)
|
|
|
(10,681
|
)
|
|
|
(10,863
|
)
|
|
|
|
|
Interest income
|
|
|
590
|
|
|
|
1,093
|
|
|
|
1,091
|
|
|
|
676
|
|
|
|
|
|
Gain (loss) on derivatives
|
|
|
(17,615
|
)
|
|
|
(108,847
|
)
|
|
|
171,209
|
|
|
|
49,746
|
|
|
|
|
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,360
|
)
|
|
|
|
|
Other income (expense)
|
|
|
58
|
|
|
|
(320
|
)
|
|
|
573
|
|
|
|
(1,211
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(29,174
|
)
|
|
|
(118,203
|
)
|
|
|
162,192
|
|
|
|
14,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and minority interest
|
|
|
36,229
|
|
|
|
31,254
|
|
|
|
214,341
|
|
|
|
29,587
|
|
|
|
|
|
Income tax expense (benefit)
|
|
|
14,106
|
|
|
|
11,620
|
|
|
|
85,302
|
|
|
|
8,812
|
|
|
|
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
22,123
|
|
|
$
|
19,634
|
|
|
$
|
129,039
|
|
|
$
|
20,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Information (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
$
|
0.23
|
|
|
$
|
1.50
|
|
|
$
|
0.24
|
|
|
|
|
|
Diluted
|
|
$
|
0.26
|
|
|
$
|
0.23
|
|
|
$
|
1.50
|
|
|
$
|
0.24
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
|
|
Diluted
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
|
|
F-61
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
Quarterly
Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
|
(in thousands except share amounts)
|
|
|
Net sales
|
|
$
|
390,483
|
|
|
$
|
843,413
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
303,670
|
|
|
|
569,623
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
113,412
|
|
|
|
60,955
|
|
Selling, general and administrative (exclusive of depreciation
and amortization)
|
|
|
13,150
|
|
|
|
14,937
|
|
Net costs associated with flood
|
|
|
|
|
|
|
2,139
|
|
Depreciation and amortization
|
|
|
14,235
|
|
|
|
17,957
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
444,467
|
|
|
|
665,611
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(53,984
|
)
|
|
|
177,802
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(11,857
|
)
|
|
|
(15,763
|
)
|
Interest income
|
|
|
452
|
|
|
|
161
|
|
Gain (loss) on derivatives
|
|
|
(136,959
|
)
|
|
|
(155,485
|
)
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
1
|
|
|
|
101
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(148,363
|
)
|
|
|
(170,986
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest
|
|
|
(202,347
|
)
|
|
|
6,816
|
|
Income tax expense (benefit)
|
|
|
(47,298
|
)
|
|
|
(93,669
|
)
|
Minority interest in (income) loss of subsidiaries
|
|
|
676
|
|
|
|
(419
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(154,373
|
)
|
|
$
|
100,066
|
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Information (Note 13)
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.79
|
)
|
|
$
|
1.16
|
|
Diluted
|
|
$
|
(1.79
|
)
|
|
$
|
1.16
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Diluted
|
|
|
86,141,291
|
|
|
|
86,158,791
|
|
F-62
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Quarter
|
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustment
|
|
|
Restated()
|
|
|
Reported
|
|
|
Adjustment
|
|
|
Restated()
|
|
|
|
(in thousands except share amounts)
|
|
|
Net sales
|
|
$
|
585,978
|
|
|
$
|
|
|
|
$
|
585,978
|
|
|
$
|
1,146,991
|
|
|
$
|
|
|
|
$
|
1,146,991
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
446,170
|
|
|
|
7,072
|
|
|
|
453,242
|
|
|
|
971,606
|
|
|
|
10,599
|
|
|
|
982,205
|
|
Direct operating expenses
(exclusive of depreciation and amortization)
|
|
|
44,440
|
|
|
|
|
|
|
|
44,440
|
|
|
|
57,331
|
|
|
|
|
|
|
|
57,331
|
|
Selling, general and administrative
(exclusive of depreciation and amortization)
|
|
|
14,035
|
|
|
|
|
|
|
|
14,035
|
|
|
|
51,000
|
|
|
|
|
|
|
|
51,000
|
|
Net costs associated with flood
|
|
|
32,192
|
|
|
|
|
|
|
|
32,192
|
|
|
|
7,192
|
|
|
|
|
|
|
|
7,192
|
|
Depreciation and amortization
|
|
|
10,481
|
|
|
|
|
|
|
|
10,481
|
|
|
|
18,106
|
|
|
|
|
|
|
|
18,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
547,318
|
|
|
|
7,072
|
|
|
|
554,390
|
|
|
|
1,105,235
|
|
|
|
10,599
|
|
|
|
1,115,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
38,660
|
|
|
|
(7,072
|
)
|
|
|
31,588
|
|
|
|
41,756
|
|
|
|
(10,599
|
)
|
|
|
31,157
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(18,340
|
)
|
|
|
|
|
|
|
(18,340
|
)
|
|
|
(15,166
|
)
|
|
|
|
|
|
|
(15,166
|
)
|
Interest income
|
|
|
151
|
|
|
|
|
|
|
|
151
|
|
|
|
336
|
|
|
|
|
|
|
|
336
|
|
Gain (loss) on derivatives
|
|
|
40,532
|
|
|
|
|
|
|
|
40,532
|
|
|
|
(30,066
|
)
|
|
|
|
|
|
|
(30,066
|
)
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,258
|
)
|
|
|
|
|
|
|
(1,258
|
)
|
Other income (expense)
|
|
|
53
|
|
|
|
|
|
|
|
53
|
|
|
|
201
|
|
|
|
|
|
|
|
201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
22,396
|
|
|
|
|
|
|
|
22,396
|
|
|
|
(45,953
|
)
|
|
|
|
|
|
|
(45,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
and minority interest
|
|
|
61,056
|
|
|
|
(7,072
|
)
|
|
|
53,984
|
|
|
|
(4,197
|
)
|
|
|
(10,599
|
)
|
|
|
(14,796
|
)
|
Income tax expense (benefit)
|
|
|
47,610
|
|
|
|
(4,879
|
)
|
|
|
42,731
|
|
|
|
11,718
|
|
|
|
(1,997
|
)
|
|
|
9,721
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
(47
|
)
|
|
|
|
|
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
13,399
|
|
|
$
|
(2,193
|
)
|
|
$
|
11,206
|
|
|
$
|
(15,915
|
)
|
|
$
|
(8,602
|
)
|
|
$
|
(24,517
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Information (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.16
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.18
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
(0.28
|
)
|
Diluted
|
|
$
|
0.16
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.18
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
(0.28
|
)
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
Diluted
|
|
|
86,158,791
|
|
|
|
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
|
()
|
|
See Note 2 to consolidated
financial statements.
|
F-63
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to
Consolidated Financial
Statements (Continued)
(21) Subsequent
Events (unaudited)
On June 13, 2008, the Company announced that the managing
general partner of the Partnership had decided to postpone
indefinitely the Partnerships initial public offering. The
Partnership has notified the SEC that it intends to withdraw the
registration statement it filed in February 2008.
F-64
CVR ENERGY, INC.
AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
(in thousands of dollars)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
25,179
|
|
|
$
|
30,509
|
|
Accounts receivable, net of allowance for doubtful accounts of
$597 and $391, respectively
|
|
|
117,033
|
|
|
|
86,546
|
|
Inventories
|
|
|
288,415
|
|
|
|
254,655
|
|
Prepaid expenses and other current assets
|
|
|
13,071
|
|
|
|
14,186
|
|
Insurance receivable
|
|
|
74,275
|
|
|
|
73,860
|
|
Income tax receivable
|
|
|
26,166
|
|
|
|
31,367
|
|
Deferred income taxes
|
|
|
78,325
|
|
|
|
79,047
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
622,464
|
|
|
|
570,170
|
|
Property, plant, and equipment, net of accumulated depreciation
|
|
|
1,192,542
|
|
|
|
1,192,174
|
|
Intangible assets, net
|
|
|
450
|
|
|
|
473
|
|
Goodwill
|
|
|
83,775
|
|
|
|
83,775
|
|
Deferred financing costs, net
|
|
|
7,028
|
|
|
|
7,515
|
|
Insurance receivable
|
|
|
11,400
|
|
|
|
11,400
|
|
Other long-term assets
|
|
|
5,932
|
|
|
|
2,849
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,923,591
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
4,862
|
|
|
$
|
4,874
|
|
Note payable and capital lease obligations
|
|
|
11,209
|
|
|
|
11,640
|
|
Payable to swap counterparty
|
|
|
294,984
|
|
|
|
262,415
|
|
Accounts payable
|
|
|
170,194
|
|
|
|
182,225
|
|
Personnel accruals
|
|
|
34,954
|
|
|
|
36,659
|
|
Accrued taxes other than income taxes
|
|
|
22,073
|
|
|
|
14,732
|
|
Deferred revenue
|
|
|
29,784
|
|
|
|
13,161
|
|
Other current liabilities
|
|
|
32,953
|
|
|
|
33,820
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
601,013
|
|
|
|
559,526
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
483,117
|
|
|
|
484,328
|
|
Accrued environmental liabilities
|
|
|
4,924
|
|
|
|
4,844
|
|
Deferred income taxes
|
|
|
287,974
|
|
|
|
286,986
|
|
Other long-term liabilities
|
|
|
4,447
|
|
|
|
1,122
|
|
Payable to swap counterparty
|
|
|
76,411
|
|
|
|
88,230
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
856,873
|
|
|
|
865,510
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Minority interest in subsidiaries
|
|
|
10,600
|
|
|
|
10,600
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
Common stock $0.01 par value per share;
350,000,000 shares authorized; 86,141,291 shares
issued and outstanding
|
|
|
861
|
|
|
|
861
|
|
Additional
paid-in-capital
|
|
|
458,523
|
|
|
|
458,359
|
|
Retained earning (deficit)
|
|
|
(4,279
|
)
|
|
|
(26,500
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
455,105
|
|
|
|
432,720
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,923,591
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the condensed consolidated financial
statements.
F-65
CVR ENERGY, INC.
AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
|
(in thousands except share amounts)
|
|
|
Net sales
|
|
$
|
1,223,003
|
|
|
$
|
390,483
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
1,036,194
|
|
|
|
303,670
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
60,556
|
|
|
|
113,412
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
13,497
|
|
|
|
13,150
|
|
Net costs associated with flood
|
|
|
5,763
|
|
|
|
|
|
Depreciation and amortization
|
|
|
19,635
|
|
|
|
14,235
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,135,645
|
|
|
|
444,467
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
87,358
|
|
|
|
(53,984
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(11,298
|
)
|
|
|
(11,857
|
)
|
Interest income
|
|
|
702
|
|
|
|
452
|
|
Loss on derivatives, net
|
|
|
(47,871
|
)
|
|
|
(136,959
|
)
|
Other income, net
|
|
|
179
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(58,288
|
)
|
|
|
(148,363
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
|
29,070
|
|
|
|
(202,347
|
)
|
Income tax expense (benefit)
|
|
|
6,849
|
|
|
|
(47,298
|
)
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
676
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
22,221
|
|
|
$
|
(154,373
|
)
|
|
|
|
|
|
|
|
|
|
Net earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
|
|
|
Diluted
|
|
$
|
0.26
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
86,141,291
|
|
|
|
|
|
Diluted
|
|
|
86,158,791
|
|
|
|
|
|
Pro Forma Information (note 11)
|
|
|
|
|
|
|
|
|
Net (loss) per share
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
$
|
(1.79
|
)
|
Diluted
|
|
|
|
|
|
$
|
(1.79
|
)
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
86,141,291
|
|
Diluted
|
|
|
|
|
|
|
86,141,291
|
|
See accompanying notes to the condensed consolidated financial
statements.
F-66
CVR ENERGY, INC.
AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
|
(in thousands of dollars)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
22,221
|
|
|
$
|
(154,373
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
19,635
|
|
|
|
14,235
|
|
Provision for doubtful accounts
|
|
|
206
|
|
|
|
(235
|
)
|
Amortization of deferred financing costs
|
|
|
495
|
|
|
|
473
|
|
Loss on disposition of fixed assets
|
|
|
16
|
|
|
|
24
|
|
Share-based compensation
|
|
|
(383
|
)
|
|
|
3,742
|
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
(676
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(30,693
|
)
|
|
|
44,627
|
|
Inventories
|
|
|
(31,642
|
)
|
|
|
(22,986
|
)
|
Prepaid expenses and other current assets
|
|
|
75
|
|
|
|
31
|
|
Insurance receivable
|
|
|
1,085
|
|
|
|
|
|
Insurance proceeds from flood
|
|
|
(1,500
|
)
|
|
|
|
|
Other long-term assets
|
|
|
(3,159
|
)
|
|
|
923
|
|
Accounts payable
|
|
|
(5,166
|
)
|
|
|
46,357
|
|
Accrued income taxes
|
|
|
5,201
|
|
|
|
14,888
|
|
Deferred revenue
|
|
|
16,623
|
|
|
|
5,067
|
|
Other current liabilities
|
|
|
5,315
|
|
|
|
3,470
|
|
Payable to swap counterparty
|
|
|
20,750
|
|
|
|
129,344
|
|
Accrued environmental liabilities
|
|
|
80
|
|
|
|
485
|
|
Other long-term liabilities
|
|
|
3,325
|
|
|
|
|
|
Deferred income taxes
|
|
|
1,710
|
|
|
|
(41,291
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
24,194
|
|
|
|
44,105
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(26,156
|
)
|
|
|
(107,363
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(26,156
|
)
|
|
|
(107,363
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Revolving debt payments
|
|
|
(123,000
|
)
|
|
|
|
|
Revolving debt borrowings
|
|
|
123,000
|
|
|
|
29,500
|
|
Principal payments on long-term debt
|
|
|
(1,223
|
)
|
|
|
|
|
Deferred costs of CVR Energy, Inc. initial public offering
|
|
|
|
|
|
|
(553
|
)
|
Deferred costs of CVR Partners, LP initial public offering
|
|
|
(2,145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(3,368
|
)
|
|
|
28,947
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(5,330
|
)
|
|
|
(34,311
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
30,509
|
|
|
|
41,919
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
25,179
|
|
|
$
|
7,608
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
|
Cash paid for income taxes, net of refunds (received)
|
|
$
|
(63
|
)
|
|
$
|
(20,895
|
)
|
Cash paid for interest
|
|
|
11,841
|
|
|
|
39
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
Accrual of construction in progress additions
|
|
|
(6,237
|
)
|
|
|
13,204
|
|
See accompanying notes to the condensed consolidated financial
statements.
F-67
CVR ENERGY, INC.
AND SUBSIDIARIES
March 31, 2008
(unaudited)
|
|
(1)
|
Organization and
History of the Company and Basis of Presentation
|
Organization
The Company or CVR may be used to refer
to CVR Energy, Inc. and, unless the context otherwise requires,
its subsidiaries. Any references to the Company as
of a date after June 24, 2005 and prior to October 16,
2007 (the date of the restructuring as further discussed in this
note) are to Coffeyville Acquisition LLC (CALLC) and its
subsidiaries.
The Company, through its wholly-owned subsidiaries, acts as an
independent petroleum refiner and marketer in the
mid-continental United States and a producer and marketer of
upgraded nitrogen fertilizer products in North America. The
Companys operations include two business segments: the
petroleum segment and the nitrogen fertilizer segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary,
incorporated in Delaware in September 2006, in order to effect
an initial public offering. The initial public offering of CVR
was consummated on October 26, 2007. In conjunction with
the initial public offering, a restructuring occurred in which
CVR became a direct or indirect owner of all of the subsidiaries
of CALLC. Additionally, in connection with the initial public
offering, CALLC was split into two entities: Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC (CALLC
II).
Initial Public
Offering of CVR Energy, Inc.
On October 26, 2007, CVR Energy, Inc. completed an initial
public offering of 23,000,000 shares of its common stock.
The initial public offering price was $19.00 per share.
The net proceeds to CVR from the initial public offering were
approximately $408.5 million, after deducting underwriting
discounts and commissions, but before deduction of offering
expenses. The Company also incurred approximately
$11.4 million of other costs related to the initial public
offering. The net proceeds from this offering were used to repay
$280.0 million of term debt under the Companys credit
facility and to repay all indebtedness under the Companys
$25.0 million unsecured facility and $25.0 million
secured facility, including related accrued interest through the
date of repayment of approximately $5.9 million.
Additionally, $50.0 million of net proceeds were used to
repay outstanding revolving loan indebtedness under the
Companys credit facility.
In connection with the initial public offering, CVR became the
indirect owner of the subsidiaries of CALLC and CALLC II. This
was accomplished by CVR issuing 62,866,720 shares of its
common stock to CALLC and CALLC II, its majority stockholders,
in conjunction with the 628,667.20 for 1 stock split of
CVRs common stock and the mergers of two newly formed
direct subsidiaries of CVR into Coffeyville Refining &
Marketing Holdings, Inc. (Refining Holdco) and Coffeyville
Nitrogen Fertilizers, Inc. (CNF). Concurrent with the merger of
the subsidiaries and in accordance with a previously executed
agreement, the Companys chief executive officer received
247,471 shares of CVR common stock in exchange for shares
that he owned of Refining Holdco and CNF. The shares were fully
vested and were exchanged at fair market value.
The Company also issued 27,100 shares of common stock to
its employees on October 24, 2007 in connection with the
initial public offering. Immediately following the completion of
the offering, there were 86,141,291 shares of common stock
outstanding, which does not include the non-vested shares noted
below.
On October 24, 2007, 17,500 shares of non-vested
common stock having a value of $365,000 at the date of grant
were issued to outside directors. Although ownership of the
shares does not transfer to the recipients until the shares have
vested, recipients have dividend and voting rights with respect
to these shares from the date of grant. The fair value of each
share of non-vested stock was
F-68
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
measured based on the market price of the common stock as of the
date of grant and is being amortized over the respective vesting
periods. One-third of the non-vested award will vest on
October 24, 2008, one-third will vest on October 24,
2009, and the final one-third will vest on October 24,
2010. Options to purchase 10,300 shares of common stock at
an exercise price of $19.00 per share were granted to outside
directors on October 22, 2007. These awards will vest over
a three year service period. Fair value was measured using an
option-pricing model at the date of grant.
Nitrogen
Fertilizer Limited Partnership
In conjunction with the consummation of CVRs initial
public offering, CVR transferred Coffeyville Resources Nitrogen
Fertilizer, LLC (CRNF), its nitrogen fertilizer business, to a
newly created limited partnership (Partnership) in exchange for
a managing general partner interest (managing GP interest), a
special general partner interest (special GP interest,
represented by special GP units) and a de minimis limited
partner interest (LP interest, represented by special LP units).
This transfer was not considered a business combination as it
was a transfer of assets among entities under common control
and, accordingly, balances were transferred at their historical
cost. CVR concurrently sold the managing GP interest to
Coffeyville Acquisition LLC III (CALLC III), an entity owned by
CVRs controlling stockholders and senior management at
fair market value. The board of directors of CVR determined,
after consultation with management, that the fair market value
of the managing general partner interest was $10.6 million.
This interest has been reflected as minority interest in the
Consolidated Balance Sheet.
CVR owns all of the interests in the Partnership (other than the
managing general partner interest and the associated incentive
distribution rights (IDRs)) and is entitled to all cash
distributed by the Partnership. The managing general partner is
not entitled to participate in Partnership distributions except
with respect to its IDRs, which entitle the managing general
partner to receive increasing percentages (up to 48%) of the
cash the Partnership distributes in excess of $0.4313 per unit
in a quarter. However, the Partnership is not permitted to make
any distributions with respect to the IDRs until the aggregate
Adjusted Operating Surplus, as defined in the amended and
restated partnership agreement, generated by the Partnership
through December 31, 2009 has been distributed in respect
of the units held by CVR and any common units issued in the
Partnerships initial public offering. The Partnership and
its subsidiaries are currently guarantors under the credit
facility of Coffeyville Resources, LLC (CRLLC), a wholly-owned
subsidiary of CVR.
The Partnership is operated by CVRs senior management
pursuant to a services agreement among CVR, the managing general
partner, and the Partnership. The Partnership is managed by the
managing general partner and, to the extent described below,
CVR, as special general partner. As special general partner of
the Partnership, CVR has joint management rights regarding the
appointment, termination, and compensation of the chief
executive officer and chief financial officer of the managing
general partner, has the right to designate two members of the
board of directors of the managing general partner, and has
joint management rights regarding specified major business
decisions relating to the Partnership. CVR, the Partnership, the
managing general partner and various of their subsidiaries also
entered into a number of agreements to regulate certain business
relations between the parties.
At March 31, 2008, the Partnership had 30,333 special LP
units outstanding, representing 0.1% of the total Partnership
units outstanding, and 30,303,000 special GP interests
outstanding, representing 99.9% of the total Partnership units
outstanding. In addition, the managing general partner owned the
managing general partner interest and the IDRs. The managing
general partner contributed 1% of CRNFs interest to the
Partnership in exchange for its managing general partner
interest and the IDRs.
On February 28, 2008, the Partnership filed a registration
statement with the Securities and Exchange Commission (SEC) to
effect the contemplated initial public offering of its common
units
F-69
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
representing limited partner interests. The registration
statement provided that upon consummation of the
Partnerships initial public offering, CVR will indirectly
own the Partnerships special general partner and
approximately 87% of the outstanding units of the Partnership.
There can be no assurance that any such offering will be
consummated on the terms described in the registration statement
or at all. The offering is under review by the SEC and as a
result the terms and resulting structure disclosed below could
be materially different.
In connection with the Partnerships initial public
offering, CRLLC will contribute all of its special LP units to
the Partnerships special general partner and all of the
Partnerships special general partner interests and special
limited partner interests will be converted into a combination
of GP units and subordinated GP units. Following the initial
public offering, as currently structured, the Partnership is
expected to have the following partnership interests outstanding:
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5,250,000 common units representing limited partner interests,
all of which the Partnership will sell in the initial public
offering;
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18,750,000 GP units representing special general partner
interests, all of which will be held by the Partnerships
special general partner;
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18,000,000 subordinated GP units representing special general
partner interests, all of which will be held by the
Partnerships special general partner; and
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a managing general partner interest, which is not entitled to
any distributions, which is held by the Partnerships
managing general partner, and incentive distribution rights
representing limited partner interests, all of which will be
held by the Partnerships managing general partner.
|
Effective with the Partnerships initial public offering,
the partnership agreement will require that the Partnership
distribute all of its cash on hand at the end of each quarter,
less reserves established by its managing general partner,
subject to a sustainability requirement in the event the
Partnership elects to increase the quarterly distribution
amount. The amount of available cash may be greater or less than
the aggregate amount necessary to make the minimum quarterly
distribution on all common units, GP units and subordinated
units.
Subsequent to the initial public offering, as currently
structured, the Partnership expects to make minimum quarterly
distributions of $0.375 per common unit ($1.50 per common unit
on an annualized basis) to the extent the Partnership has
sufficient available cash. In general, cash distributions will
be made each quarter as follows:
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First, to the holders of common units and GP units until each
common unit and GP unit has received a minimum quarterly
distribution of $0.375 plus any arrearages from prior quarters;
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Second, to the holders of subordinated units, until each
subordinated unit has received a minimum quarterly distribution
of $0.375; and
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Third, to all unitholders, pro rata, until each unit has
received a quarterly distribution of $0.4313.
|
If cash distributions exceed $0.4313 per unit in a quarter, the
Partnerships managing general partner, as holder of the
IDRs, will receive increasing percentages, up to 48%, of the
cash the Partnership distributes in excess of $0.4313 per unit.
However, the managing general partner will not be entitled to
receive any distributions in respect of the IDRs until the
Partnership has made cash distributions in an aggregate amount
equal to the Partnerships adjusted operating surplus
generated during the period from the closing of the
Partnerships initial public offering until
December 31, 2009.
During the subordination period, the subordinated units will not
be entitled to receive any distributions until the common units
and GP units have received the minimum quarterly distribution of
F-70
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
$0.375 per unit plus any arrearages from prior quarters. The
subordination period begins on the closing date of the
Partnerships initial public offering and will end once the
Partnership meets the financial tests in the partnership
agreement. When the subordination period ends, all subordinated
units will convert into GP units or common units on a
one-for-one basis, and the common units and GP units will no
longer be entitled to arrearages.
If the Partnership meets the financial tests in the partnership
agreement for any three consecutive four-quarter periods ending
on or after the first quarter whose last day is at least three
years after the closing of Partnership Offering, 25% of the
subordinated GP units will convert into GP units on a
one-for-one basis. If the Partnership meets these financial
tests for any three consecutive four-quarter periods ending on
or after the first quarter whose last day is at least four years
after the closing of the Partnership Offering, an additional 25%
of the subordinated GP units will convert into GP units on a
one-for-one basis. The early conversion of the second 25% of the
subordinated GP units may not occur until at least one year
following the end of the last four-quarter period in respect of
which the first 25% of the subordinated GP units were converted.
If the subordinated GP units have converted into subordinated LP
units at the time the financial tests are met they will convert
into common units, rather than GP units. In addition, the
subordination period will end if the managing general partner is
removed as the managing general partner where cause
(as defined in the partnership agreement) does not exist and no
units held by any holder of subordinated units or its affiliates
are voted in favor of that removal.
The partnership agreement authorizes the Partnership to issue an
unlimited number of additional units and rights to buy units for
the consideration and on the terms and conditions determined by
the managing general partner without the approval of the
unitholders.
The Partnership will distribute all cash received by it or its
subsidiaries in respect of accounts receivable existing as of
the closing of the initial public offering exclusively to its
special general partner.
The managing general partner, together with the special general
partner, manages and operates the Partnership. Common
unitholders will only have limited voting rights on matters
affecting the Partnership. In addition, common unitholders will
have no right to elect either of the general partners or the
managing general partners directors on an annual or other
continuing basis.
If at any time the managing general partner and its affiliates
own more than 80% of the common units, the managing general
partner will have the right, but not the obligation, to purchase
all of the remaining common units at a purchase price equal to
the greater of (x) the average of the daily closing price
of the common units over the 20 trading days preceding the date
three days before notice of exercise of the call right is first
mailed and (y) the highest
per-unit
price paid by the managing general partner or any of its
affiliates for common units during the
90-day
period preceding the date such notice is first mailed.
Basis of
Presentation
The accompanying unaudited condensed consolidated financial
statements were prepared in accordance with U.S. generally
accepted accounting principles (GAAP) and in accordance with the
rules and regulations of the SEC. The consolidated financial
statements include the accounts of CVR Energy, Inc. and its
majority-owned direct and indirect subsidiaries. The ownership
interests of minority investors in its subsidiaries are recorded
as minority interest. All intercompany accounts and transactions
have been eliminated in consolidation. Certain information and
footnotes required for the complete financial statements under
GAAP have been condensed or omitted pursuant to such rules and
regulations. These unaudited condensed consolidated financial
statements should be read in conjunction with the
December 31, 2007 audited consolidated financial statements
and notes thereto included in CVRs Annual Report on
Form 10-K/A
for the year ended December 31, 2007.
F-71
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
In the opinion of the Companys management, the
accompanying unaudited condensed consolidated financial
statements reflect all adjustments (consisting only of normal
recurring adjustments) that are necessary to fairly present the
financial position of the Company as of March 31, 2008 and
December 31, 2007, the results of operations for the three
months ended March 31, 2008 and 2007, and the cash flows
for the three months ended March 31, 2008 and 2007.
Results of operations and cash flows for the interim periods
presented are not necessarily indicative of the results that
will be realized for the year ending December 31, 2008 or
any other interim period. The preparation of financial
statements in conformity with U.S. generally accepted
accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosure of
contingent assets and liabilities. Actual results could differ
from those estimates.
In connection with CVRs initial public offering,
$0.5 million of deferred offering costs for the three
months ended March 31, 2007 were previously presented in
operating activities in the interim financial statements. Such
amounts have now been reflected as financing activities for the
three months ended March 31, 2007 in the accompanying
Consolidated Statements of Cash Flows. The impact on the prior
financial statements of this revision is not considered material.
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(2)
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Recent Accounting
Pronouncements
|
In September 2006, the Financial Accounting Standards Board
(FASB) issued Statement on Financial Accounting Standards (SFAS)
No. 157,
Fair Value Measurements
, which establishes
a framework for measuring fair value in GAAP and expands
disclosures about fair value measurements.
SFAS 157 states that fair value is the price
that would be received to sell the asset or paid to transfer the
liability (an exit price), not the price that would be paid to
acquire the asset or received to assume the liability (an entry
price). The standards provisions for financial
assets and financial liabilities, which became effective
January 1, 2008, had no material impact on the
Companys financial position or results of operations. At
March 31, 2008, the only financial assets and financial
liabilities that are measured at fair value on a recurring basis
are the Companys derivative instruments. See Note 14,
Fair Value Measurements.
In February 2008, the FASB issued FASB Staff Position
157-2
which
defers the effective date of SFAS 157 for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in an entitys
financial statements on a recurring basis (at least annually).
The Company will be required to adopt SFAS 157 for these
nonfinancial assets and nonfinancial liabilities as of
January 1, 2009. Management believes the adoption of
SFAS 157 deferral provisions will not have a material
impact on the Companys financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,
The
Fair Value Option for Financial Assets and Financial
Liabilities
. Under this standard, an entity is required to
provide additional information that will assist investors and
other users of financial information to more easily understand
the effect of the Companys choice to use fair value on its
earnings. Further, the entity is required to display the fair
value of those assets and liabilities for which the Company has
chosen to use fair value on the face of the balance sheet. This
standard does not eliminate the disclosure requirements about
fair value measurements included in SFAS No. 107,
Disclosures about Fair Value of Financial Instruments
.
The provisions of SFAS 159 were effective for CVR as of
January 1, 2008. The Company did not elect the fair value
option under this standard upon adoption. Therefore, the
adoption of SFAS 159 did not impact the Companys
consolidated financial statements as of the quarter ended
March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
. This statement defines the
acquirer as the entity that obtains control of one or more
businesses in the business combination, establishes the
acquisition date as the date that the acquirer achieves control
and requires the acquirer to recognize the assets acquired,
liabilities assumed and any non-controlling
F-72
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
interest at their fair values as of the acquisition date. This
statement also requires that acquisition-related costs of the
acquirer be recognized separately from the business combination
and will generally be expensed as incurred. CVR will be required
to adopt this statement as of January 1, 2009. The impact
of adopting SFAS 141R will be limited to any future
business combinations for which the acquisition date is on or
after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting standards
for the non-controlling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a
non-controlling interest in a subsidiary is an ownership
interest in the consolidated entity that should be reported as
equity in the consolidated financial statements. SFAS 160
requires retroactive adoption of the presentation and disclosure
requirements for existing minority interests. All other
requirements of SFAS 160 must be applied prospectively.
SFAS 160 is effective for CVR beginning January 1,
2009. The Company is currently evaluating the potential impact
of the adoption of SFAS 160 on its consolidated financial
statements.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133
. This statement will change the disclosure
requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about how
and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
Statement 133 and its related interpretations, and how
derivative instruments and related hedged items affect an
entitys financial position, net earnings, and cash flows.
The Company will be required to adopt this statement as of
January 1, 2009. The adoption of SFAS 161 is not
expected to have a material impact on the Companys
consolidated financial statements.
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(3)
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Share Based
Compensation
|
Prior to CVRs initial public offering, CVRs
subsidiaries were held and operated by CALLC, a limited
liability company. Management of CVR holds an equity interest in
CALLC. CALLC had issued non-voting override units to certain
management members who held common units of CALLC. There were no
required capital contributions for the override operating units.
In connection with CVRs initial public offering in October
2007, CALLC was split into two entities: CALLC and CALLC II. In
connection with this split, managements equity interest in
CALLC, including both their common units and non-voting override
units, was split so that half of managements equity
interest was in CALLC and half was in CALLC II. CALLC was
historically the primary reporting company and CVRs
predecessor. In connection with the restructuring of the Company
related to the Partnership, CALLC III issued non-voting override
units to certain management members of CALLC III.
CVR, CALLC, CALLC II and CALLC III account for share-based
compensation in accordance with SFAS No. 123(R),
Share-Based Payments
and
EITF 00-12,
Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee
. CVR has
recorded non-cash share-based compensation expense from CALLC,
CALLC II and CALLC III.
In accordance with SFAS 123(R), CVR, CALLC, CALLC II and
CALLC III apply a fair value based measurement method in
accounting for share-based compensation. In accordance with
EITF 00-12,
CVR recognizes the costs of the share-based compensation
incurred by CALLC, CALLC II and CALLC III on its behalf,
primarily in selling, general, and administrative expenses
(exclusive of depreciation and amortization), and a
corresponding capital contribution, as the costs are incurred on
its behalf, following the guidance in
EITF 96-18,
Accounting for Equity Investments That Are Issued to Other
Than Employees for Acquiring, or in Conjunction with Selling
Goods or Services
, which requires remeasurement at each
reporting period. At March 31, 2008, CVRs common
stock closing price was utilized to determine the fair value of
the override units of CALLC and CALLC II. The estimated fair
F-73
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
value per unit reflects a ratio of override units to shares of
common stock. The estimated fair value of the override units of
CALLC III has been determined using a binomial and
probability-weighted expected return method which utilizes CALLC
IIIs cash flow projections, which are representative of
the nature of interests held by CALLC III in the Partnership.
The following describes the share-based compensation plans of
CALLC, CALLC II, CALLC III and CRLLC, CVRs indirect wholly
owned subsidiary.
919,630
Override Operating Units at an Adjusted Benchmark Value of
$11.31 per Unit
In June 2005, CALLC issued 919,630 non-voting override operating
units to certain management members holding common units of
CALLC. There were no required capital contributions for the
override operating units.
In accordance with SFAS 123(R),
Share Based
Compensation
, using the Monte Carlo method of valuation, the
estimated fair value of the override operating units on
June 24, 2005 was $3,605,000. Pursuant to the forfeiture
schedule described below, CVR recognized compensation expense
over the service period for each separate portion of the award
for which the forfeiture restriction lapsed as if the award was,
in substance, multiple awards. Compensation expense of
$(558,000) and $285,000 was recognized for the three months
ending March 31, 2008 and 2007, respectively.
In connection with the split of CALLC into two entities on
October 16, 2007, managements equity interest in
CALLC was split so that half of managements equity
interest is in CALLC and half is in CALLC II. The restructuring
resulted in a modification of the existing awards under
SFAS 123(R). However, because the fair value of the
modified award equaled the fair value of the original award
before the modification, there was no accounting consequence as
a result of the modification. However, due to the restructuring,
the employees of CVR and the Partnership no longer hold
share-based awards in a parent company. Due to the change in
status of the employees related to the awards, CVR recognized
compensation expense for the newly measured cost attributable to
the remaining vesting (service) period prospectively from the
date of the change in status.
Significant assumptions used in the valuation were as follows:
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Remeasurement
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Grant Date
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Date
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Estimated forfeiture rate
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None
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None
|
Explicit service period
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Based on forfeiture
schedule below
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Based on forfeiture
schedule below
|
Grant date fair value
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$5.16 per share
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N/A
|
March 31, 2008 CVR closing stock price
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N/A
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$23.03
|
March 31, 2008 estimated fair value
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N/A
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$47.88 per share
|
Marketability and minority interest discounts
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24% discount
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15% discount
|
Volatility
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37%
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N/A
|
72,492
Override Operating Units at a Benchmark Value of $34.72 per
Unit
On December 28, 2006, CALLC issued 72,492 additional
non-voting override operating units to a management member who
held common units of CALLC. There were no required capital
contributions for the override operating units.
In accordance with SFAS 123(R), a combination of a binomial
model and a probability-weighted expected return method which
utilized CVRs cash flow projections resulted in an
estimated fair value of the override operating units on
December 28, 2006 of $473,000. Management believed that
this method was preferable for the valuation of the override
units as it allowed a better integration of the cash flows with
other inputs, including the timing of potential exit events that
impact the estimated fair
F-74
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
value of the override units. These override operating units are
being accounted for the same as the override operating units
with the adjusted benchmark value of $11.31 per unit. In
accordance with the accounting method noted above and pursuant
to the forfeiture schedule described below, CVR recognized
compensation expense of $6,000 and $100,000 for the periods
ending March 31, 2008 and 2007, respectively.
Significant assumptions used in the valuation were as follows:
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Remeasurement
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Grant Date
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Date
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Estimated forfeiture rate
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None
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None
|
Explicit service period
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Based on forfeiture
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Based on forfeiture
|
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schedule below
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schedule below
|
Grant date fair value
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$8.15 per share
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N/A
|
March 31, 2008 CVR closing stock price
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N/A
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$23.03
|
March 31, 2008 estimated fair value
|
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N/A
|
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$28.68 per share
|
Marketability and minority interest discounts
|
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20% discount
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15% discount
|
Volatility
|
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41%
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N/A
|
Override operating units are forfeited upon termination of
employment for cause. In the event of all other terminations of
employment, the override operating units are initially subject
to forfeiture with the number of units subject to forfeiture
reducing as follows:
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Forfeiture
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Minimum Period Held
|
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Rate
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2 years
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75
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%
|
3 years
|
|
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50
|
%
|
4 years
|
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25
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%
|
5 years
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0
|
%
|
On the tenth anniversary of the issuance of override operating
units, such units convert into an equivalent number of override
value units.
1,839,265
Override Value Units at an Adjusted Benchmark Value of $11.31
per Unit
In June 2005, CALLC issued 1,839,265 non-voting override value
units to certain management members who held common units of
CALLC. There were no required capital contributions for the
override value units.
In accordance with SFAS 123(R), using the Monte Carlo
method of valuation, the estimated fair value of the override
value units on June 24, 2005 was $4,065,000. For the
override value units, CVR is recognizing compensation expense
ratably over the implied service period of 6 years. These
override value units are being accounted for the same as the
override operating units with an adjusted benchmark value of
$11.31 per unit. In accordance with the accounting method noted
above, CVR recognized compensation expense of $533,000 and
$169,000 for the three months ending March 31, 2008 and
2007, respectively.
F-75
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
|
|
Remeasurement
|
|
|
Grant Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$2.91 per share
|
|
N/A
|
March 31, 2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$47.88 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
N/A
|
144,966
Override Value Units at a Benchmark Value of $34.72 per
Unit
On December 28, 2006, CALLC issued 144,966 additional
non-voting override value units to a management member who held
common units of CALLC. There were no required capital
contributions for the override value units.
In accordance with SFAS 123(R), a combination of a binomial
model and a probability-weighted expected return method which
utilized CVRs cash flow projections resulted in an
estimated fair value of the override value units on
December 28, 2006 of $945,000. Management believed that
this method was preferable for the valuation of the override
units as it allowed a better integration of the cash flows with
other inputs, including the timing of potential exit events that
impacted the estimated fair value of the override units. These
override value units are being accounted for the same as the
override operating units with the adjusted benchmark value of
$11.31 per unit. In accordance with the accounting method noted
above, CVR recognized compensation expense of $91,000, and
$52,000 for the three months ending March 31, 2008 and
2007, respectively.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
|
|
Remeasurement
|
|
|
Grant Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$8.15 per share
|
|
N/A
|
March 31, 2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$28.68 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
N/A
|
Unless the compensation committee of the board of directors of
CVR takes an action to prevent forfeiture, override value units
are forfeited upon termination of employment for any reason
except that in the event of termination of employment by reason
of death or disability, all override value units are initially
subject to forfeiture with the number of units subject to
forfeiture reducing as follows:
|
|
|
|
|
|
|
Subject to
|
|
|
|
Forfeiture
|
|
Minimum Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
F-76
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
At March 31, 2008, assuming no change in the estimated fair
value at March 31, 2008, there was approximately
$59.2 million of unrecognized compensation expense related
to non-voting override units. This is expected to be recognized
over a remaining period of four years as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
|
|
Operating Units
|
|
|
Value Units
|
|
|
Nine months ending December 31, 2008
|
|
$
|
4,927
|
|
|
$
|
11,688
|
|
Year ending December 31, 2009
|
|
|
3,762
|
|
|
|
15,585
|
|
Year ending December 31, 2010
|
|
|
1,120
|
|
|
|
15,584
|
|
Year ending December 31, 2011
|
|
|
|
|
|
|
6,569
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,809
|
|
|
$
|
49,426
|
|
|
|
|
|
|
|
|
|
|
138,281
Override Units with a Benchmark Amount of $10
In October 2007, CALLC III issued 138,281 non-voting override
units to certain management members who held common units of
CALLC III. There were no required capital contributions for the
override units.
In accordance with SFAS 123(R),
Share Based
Compensation
, using a binomial and a probability-weighted
expected return method which utilized CALLC IIIs cash flow
projections, the estimated fair value of the operating units at
March 31, 2008 was immaterial. CVR recognizes compensation
costs for this plan based on the fair value of the awards at the
end of each reporting period in accordance with
EITF 00-12
using the guidance in
EITF 96-18.
In accordance with
EITF 00-12,
as a noncontributing investor, CVR also recognized income equal
to the amount that its interest in the Partnerships net
book value has increased (that is, its percentage share of the
contributed capital recognized by the investee) as a result of
the disproportionate funding of the compensation costs. This
amount equaled the compensation expense recognized for these
awards for the three months ended March 31, 2008. Pursuant
to the forfeiture schedule reflected above, CVR recognized
compensation expense over this service period for each portion
of the award for which the forfeiture restriction has lapsed. As
of March 31, 2008, these override units are fully vested.
Significant assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
March 31, 2008 estimated fair value
|
|
$0.004 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
36.2%
|
642,219
Override Units with a Benchmark Amount of $10
On February 15, 2008, CALLC III issued 642,219 non-voting
override units to certain management members of CALLC III. There
were no required capital contributions for the override units.
In accordance with SFAS 123(R),
Share Based
Compensation,
using a binomial and a probability-weighted
expected return method which utilized CALLC IIIs cash
flows projections, the estimated fair value of the operating
units at March 31, 2008 was immaterial. CVR recognizes
compensation costs for this plan based on the fair value of the
awards at the end of each reporting period in accordance with
EITF 00-12
using the guidance in
EITF 96-18.
In accordance with
EITF 00-12,
as a noncontributing investor, CVR also recognized income equal
to the amount that its interest in the investees net book
value has increased (that is, its percentage share of the
contributed capital recognized by the investee) as a result of
the disproportionate funding of the compensation costs. CVR
recognized compensation expense of $600 for the three months
ended March 31, 2008. Pursuant to the forfeiture schedule
of the amended and restated partnership agreement of CALLC III,
F-77
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
CVR recognized compensation expense over this service period for
each portion of the award for which the forfeiture restriction
has lapsed. Of the 642,219 units issued, 109,720 were
immediately vested upon issuance and the remaining units are
subject to the forfeiture schedule.
Significant assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
Derived Service Period
|
|
Based on forfeiture schedule
|
March 31, 2008 estimated fair value
|
|
$0.004 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
36.2%
|
Phantom Unit
Appreciation Plan
The Company, through a wholly-owned subsidiary, has a Phantom
Unit Appreciation Plan whereby directors, employees, and service
providers may be awarded phantom points at the discretion of the
board of directors or the compensation committee. Holders of
service phantom points have rights to receive distributions when
holders of override operating units receive distributions.
Holders of performance phantom points have rights to receive
distributions when holders of override value units receive
distributions. There are no other rights or guarantees, and the
plan expires on July 25, 2015 or at the discretion of the
compensation committee of the board of directors. As of
March 31, 2008, the issued Profits Interest (combined
phantom plan and override units) represented 15% of combined
common unit interest and Profits Interest of CALLC and CALLC II.
The Profits Interest was comprised of 11.1% and 3.9% of override
interest and phantom interest, respectively. In accordance with
SFAS 123(R), using the March 31, 2008 CVR stock
closing price to determine the Companys equity value,
through an independent valuation process, the service phantom
interest and performance phantom interest were both valued at
$47.88 per point. CVR has recorded approximately $28,670,000 and
$29,217,000 in personnel accruals as of March 31, 2008 and
December 31, 2007, respectively. Compensation expense for
the three month periods ending March 31, 2008 and 2007
related to the Phantom Unit Appreciation Plan was $(547,000) and
$3,136,000, respectively.
At March 31, 2008, assuming no change in the estimated fair
value at March 31, 2008, there was approximately
$20.6 million of unrecognized compensation expense related
to the Phantom Unit Appreciation Plan. This is expected to be
recognized over a remaining period of four years.
Long Term
Incentive Plan
CVR has a Long Term Incentive Plan. There were no awards granted
under this plan in the first quarter of 2008.
On October 24, 2007, 17,500 shares of non-vested
common stock having a fair value of $365,000 at the date of
grant were issued to outside directors. Although ownership of
the shares does not transfer to the recipients until the shares
have vested, recipients have dividend and voting rights on these
shares from the date of grant. The fair value of each share of
non-vested common stock was measured based on the market price
of the common stock as of the date of grant and will be
amortized over the respective vesting periods. One-third will
vest on October 24, 2008, 2009 and 2010, respectively.
Options to purchase 10,300 shares of common stock at an
exercise price of $19.00 per share were granted to outside
directors on October 22, 2007. Options to purchase
8,600 shares of common stock at an exercise price of $24.73
per share were granted to outside directors on December 21,
2007.
During the quarter there were no issuances, forfeitures or
vesting of stock options or non-vested shares.
F-78
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
As of March 31, 2008, there was approximately
$0.2 million of total unrecognized compensation cost
related to non-vested shares to be recognized over a
weighted-average period of approximately one year. Compensation
expense recorded for the three month periods ending
March 31, 2008 and 2007 related to the non-vested stock was
$56,000 and $0, respectively. Compensation expense for the three
month periods ending March 31, 2008 and 2007 related to
stock options was $36,000 and $0, respectively.
Inventories consist primarily of crude oil, blending stock and
components, work in progress, fertilizer products, and refined
fuels and by-products. Inventories are valued at the lower of
the
first-in,
first-out (FIFO) cost, or market, for fertilizer products,
refined fuels and by-products for all periods presented.
Refinery unfinished and finished products inventory values were
determined using the ability-to-bare process, whereby raw
materials and production costs are allocated to
work-in-process
and finished products based on their relative fair values. Other
inventories, including other raw materials, spare parts, and
supplies, are valued at the lower of moving-average cost, which
approximates FIFO, or market. The cost of inventories includes
inbound freight costs.
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Finished goods
|
|
$
|
123,814
|
|
|
$
|
109,394
|
|
Raw materials and catalysts
|
|
|
123,042
|
|
|
|
92,104
|
|
In-process inventories
|
|
|
17,045
|
|
|
|
29,817
|
|
Parts and supplies
|
|
|
24,514
|
|
|
|
23,340
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
288,415
|
|
|
$
|
254,655
|
|
|
|
|
|
|
|
|
|
|
|
|
(5)
|
Property, Plant,
and Equipment
|
A summary of costs for property, plant, and equipment is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Land and improvements
|
|
$
|
13,170
|
|
|
$
|
13,058
|
|
Buildings
|
|
|
19,351
|
|
|
|
17,541
|
|
Machinery and equipment
|
|
|
1,277,292
|
|
|
|
1,108,858
|
|
Automotive equipment
|
|
|
5,752
|
|
|
|
5,171
|
|
Furniture and fixtures
|
|
|
6,420
|
|
|
|
6,304
|
|
Leasehold improvements
|
|
|
929
|
|
|
|
929
|
|
Construction in progress
|
|
|
30,859
|
|
|
|
182,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,353,773
|
|
|
|
1,333,907
|
|
Accumulated depreciation
|
|
|
161,231
|
|
|
|
141,733
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,192,542
|
|
|
$
|
1,192,174
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest recognized as a reduction in interest
expense for the periods ended March 31, 2008, and
March 31, 2007 totaled approximately $1,118,000 and
$4,079,000, respectively.
|
|
(6)
|
Planned Major
Maintenance Costs
|
The direct-expense method of accounting is used for planned
major maintenance activities. Maintenance costs are recognized
as expense when maintenance services are performed. The
F-79
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
Coffeyville nitrogen fertilizer plant last completed a major
scheduled turnaround in the third quarter of 2006 and is
scheduled to complete a turnaround in the fourth quarter of
2008. The Coffeyville refinery started a major scheduled
turnaround in February 2007 with completion in April 2007. Costs
of $66,003,000 associated with the 2007 refinery turnaround were
included in direct operating expenses (exclusive of depreciation
and amortization) for the three months ending March 31,
2007.
Cost of product sold (exclusive of depreciation and
amortization) includes cost of crude oil, other feedstocks,
blendstocks, pet coke expense and freight and distribution
expenses. Cost of product sold excludes depreciation and
amortization of $600,000 and $619,000 for the three months ended
March 31, 2008 and March 31, 2007, respectively.
Direct operating expenses (exclusive of depreciation and
amortization) includes direct costs of labor, maintenance and
services, energy and utility costs, environmental compliance
costs as well as chemicals and catalysts and other direct
operating expenses. Direct operating expenses excludes
depreciation and amortization of $18,703,000 and $13,530,000 for
the three months ended March 31, 2008 and March 31,
2007, respectively.
Selling, general and administrative expenses (exclusive of
depreciation and amortization) consists primarily of legal
expenses, treasury, accounting, marketing, human resources and
maintaining the corporate offices in Texas and Kansas. Selling,
general and administrative expenses excludes depreciation and
amortization of $332,000 and $86,000 for the three months ended
March 31, 2008 and March 31, 2007, respectively.
|
|
(8)
|
Note Payable and
Capital Lease Obligations
|
The Company entered into an insurance premium finance agreement
with Cananwill, Inc. in July 2007 to finance the purchase of its
property, liability, cargo and terrorism policies. The original
balance of the note was $7.6 million and required repayment
in nine equal installments with final payment due in April 2008.
The balance due was paid in full in April 2008. As of
March 31, 2008 and December 31, 2007, $0.8 and
$3.4 million related to this insurance premium finance
agreement was included in note payable and capital lease
obligations on the Consolidated Balance Sheet, respectively.
The Company entered into two capital leases in 2007 to lease
platinum required in the manufacturing of a new catalyst. The
recorded lease obligations fluctuate with the platinum market
price. The leases will terminate on the date an equal amount of
platinum is returned to each lessor, with the difference to be
paid in cash. One lease was settled and terminated in January
2008. At March 31, 2008 and December 31, 2007 the
lease obligations were recorded at approximately
$10.4 million and $8.2 million on the Consolidated
Balance Sheets, respectively.
|
|
(9)
|
Flood and
Insurance Related Matters
|
On June 30, 2007, torrential rains in southeast Kansas
caused the Verdigris River to overflow its banks and flood the
town of Coffeyville, Kansas. As a result, the Companys
refinery and nitrogen fertilizer plant were severely flooded,
resulting in significant damage to the refinery assets. The
nitrogen fertilizer facility also sustained damage, but to a
much lesser degree. The Company maintained property damage
insurance which included damage caused by a flood, of up to
$300 million per occurrence, subject to deductibles and
other limitations. The deductible associated with the property
damage was $2.5 million.
Management continues to work closely with the Companys
insurance carriers and claims adjusters to ascertain the full
amount of insurance proceeds due to the Company as a result of
the damages and losses. At March 31, 2008, total accounts
receivable from insurance was $85.7 million. The receivable
balance is segregated between current and long-term in the
Companys Consolidated
F-80
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
Balance Sheet in relation to the nature and classification of
the items to be settled. Management believes the recovery of the
receivable from the insurance carriers is probable.
Approximately $11.4 million of the receivable recorded at
March 31, 2008 relates to the crude oil discharge and the
remaining $74.3 million relates to the flood damage to the
Companys facilities. While management believes that the
Companys property insurance should cover substantially all
of the estimated total physical damage to the property, the
Companys insurance carriers have cited potential coverage
limitations and defenses that might preclude such a result.
The Companys insurance policies also provide coverage for
interruption to the business, including lost profits, and
reimbursement for other expenses and costs the Company has
incurred relating to the damages and losses suffered for
business interruption. This coverage, however, only applies to
losses incurred after a business interruption of 45 days.
Because the fertilizer plant was restored to operation within
this
45-day
period and the refinery restarted its last operating unit in
48 days, a substantial portion of the lost profits incurred
because of the flood cannot be claimed under insurance. The
Company continues to assess its policies to determine how much,
if any, of its lost profits after the
45-day
period are recoverable. No amounts for recovery of lost profits
under the Companys business interruption policy have been
recorded in the accompanying consolidated financial statements.
The Company has recorded pretax costs in total of approximately
$47.3 million associated with the flood and related crude
oil discharge as discussed in Note 12, Commitments
and Contingent Liabilities, including $5.8 million of
net pretax costs in the first quarter of 2008. These amounts are
net of anticipated insurance recoveries of $107.2 million
including $1.8 million of recoveries for the first quarter
of 2008. These costs are reported in Net costs associated
with flood in the Consolidated Statements of Operations.
Total gross costs recorded due to the flood and related oil
discharge that were included in the Consolidated Statements of
Operations for the three months ended March 31, 2008 were
$7.6 million. Of these gross costs for the three month
period ended March 31, 2008, $3.8 million were
associated with repair and other matters as a result of the
flood damage to the Companys facilities. Included in this
cost was $0.3 million of professional fees and
$3.5 million for other repair and related costs. There were
also $3.8 million of costs recorded for the three month
period ended March 31, 2008 related to the third party and
property damage remediation as a result of the crude oil
discharge.
Below is a summary of the gross cost and reconciliation of the
insurance receivable (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
|
|
|
|
|
|
|
Months Ended
|
|
|
|
Total Costs
|
|
|
March 31, 2008
|
|
|
Total gross costs incurred
|
|
$
|
154.5
|
|
|
$
|
7.6
|
|
Total insurance receivable
|
|
|
(107.2
|
)
|
|
|
(1.8
|
)
|
|
|
|
|
|
|
|
|
|
Net costs associated with the flood
|
|
$
|
47.3
|
|
|
$
|
5.8
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
Reconciliation
|
|
|
Total insurance receivable
|
|
$
|
107.2
|
|
Less insurance proceeds received
|
|
|
(21.5
|
)
|
|
|
|
|
|
Insurance receivable
|
|
$
|
85.7
|
|
The Company anticipates that approximately $2.1 million in
additional third party costs related to the repair of flood
damaged property will be recorded in future periods. Although
the Company believes that it will recover substantial sums under
its insurance policies, the Company is not sure of the ultimate
amount or timing of such recovery because of the difficulty
inherent in projecting the
F-81
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
ultimate resolution of the Companys claims. The difference
between what the Company ultimately receives under its insurance
policies compared to what has been recorded and described above
could be material to the consolidated financial statements.
In 2007, the Company had received insurance proceeds of
$10.0 million under its property insurance policy and
$10.0 million under its environmental policies related to
recovery of certain costs associated with the crude oil
discharge. In the first quarter of 2008, the Company received
$1.5 million under its Builders Risk Insurance
Policy. See Note 12, Commitments and Contingent
Liabilities for additional information regarding
environmental and other contingencies relating to the crude oil
discharge that occurred on July 1, 2007.
The Company adopted the provisions of FASB Interpretation
No. 48,
Accounting for Uncertain Tax
Positions an interpretation of FASB
No. 109
(FIN 48) on January 1, 2007. The
adoption of FIN 48 did not affect the Companys
financial position or results of operations. The Company does
not have any unrecognized tax benefits as of March 31, 2008.
The Company did not accrue or recognize any amounts for interest
or penalties in its financial statements for the three months
ended March 31, 2008. The Company will classify interest to
be paid on an underpayment of income taxes and any related
penalties as income tax expense if it is determined, in a
subsequent period, that a tax position is not more likely than
not of being sustained.
CVR and its subsidiaries file U.S. federal and various
state income tax returns. The Company is currently under a
U.S. federal income tax examination for its 2005 tax year.
The Company has not been subject to any other U.S. federal,
state or local income tax examinations by tax authorities for
any tax year. The U.S. federal and state tax years subject
to examination are 2004 to 2007. As of March 31, 2008, no
taxing authority has proposed any adjustments to the
Companys tax positions.
The Companys effective tax rates for the three months
ended March 31, 2008 and 2007 were 23.6% and 23.4%,
respectively, as compared to the federal statutory tax rate of
35%. The effective tax rate is lower than the statutory rate due
to federal income tax credits available to small business
refiners related to the production of ultra low sulfur diesel
fuel and Kansas state incentives generated under the High
Performance Incentive Program (HPIP).
|
|
(11)
|
Earnings (Loss)
Per Share
|
On October 26, 2007, the Company completed the initial
public offering of 23,000,000 shares of its common stock.
Also, in connection with the initial public offering, a
reorganization of entities under common control was consummated
whereby the Company became the indirect owner of the
subsidiaries of CALLC and CALLC II and all of their refinery and
fertilizer assets. This reorganization was accomplished by the
Company issuing 62,866,720 shares of its common stock to
CALLC and CALLC II, its majority stockholders, in conjunction
with a 628,667.20 for 1 stock split and the merger of two newly
formed direct subsidiaries of CVR. Immediately following the
completion of the offering, there were 86,141,291 shares of
common stock outstanding, excluding non-vested shares issued.
See Note 1, Organization and History of Company and
Basis of Presentation.
Earnings per share for the three months ended March 31,
2008 is calculated as noted below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
Shares
|
|
|
Per Share
|
|
|
Basic earnings per share
|
|
$
|
22,221,000
|
|
|
|
86,141,291
|
|
|
$
|
0.26
|
|
Diluted earnings per share
|
|
$
|
22,221,000
|
|
|
|
86,158,791
|
|
|
$
|
0.26
|
|
Outstanding stock options totaling 18,900 common shares were
excluded from the diluted earnings per share calculation for the
three months ended March 31, 2008 as they were antidilutive.
F-82
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
The computation of basic and diluted loss per share for the
quarter ended March 31, 2007 is calculated on a pro forma
basis assuming the capital structure in place after the
completion of the offering was in place for the entire period.
Pro forma loss per share for the three months ended
March 31, 2007 is calculated as noted below. For the three
months ended March 31, 2007, 17,500 non-vested shares of
common stock and 18,900 common stock options have been excluded
from the calculation of pro forma diluted earnings per share
because the inclusion of such common stock equivalents in the
number of weighted average shares outstanding would be
anti-dilutive:
|
|
|
|
|
|
|
March 31, 2007
|
|
|
|
(unaudited)
|
|
|
Net (loss)
|
|
$
|
(154,373,000
|
)
|
Pro forma weighted average shares outstanding:
|
|
|
|
|
Original CVR shares of common stock
|
|
|
100
|
|
Effect of 628,667.20 to 1 stock split
|
|
|
62,866,620
|
|
Issuance of shares of common stock to management in exchange for
subsidiary shares
|
|
|
247,471
|
|
Issuance of shares of common stock to employees
|
|
|
27,100
|
|
Issuance of shares of common stock in the initial public offering
|
|
|
23,000,000
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
86,141,291
|
|
Dilutive securities issuance of non-vested shares of
common stock to board of directors
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
86,141,291
|
|
|
|
|
|
|
Pro forma basic loss per share
|
|
$
|
(1.79
|
)
|
Pro forma dilutive loss per share
|
|
$
|
(1.79
|
)
|
|
|
(12)
|
Commitments and
Contingent Liabilities
|
The minimum required payments for the Companys lease
agreements and unconditional purchase obligations are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Unconditional
|
|
|
|
Leases
|
|
|
Purchase Obligations
|
|
|
Nine months ending December 31, 2008
|
|
$
|
2,833
|
|
|
$
|
20,757
|
|
Year ending December 31, 2009
|
|
|
3,266
|
|
|
|
28,229
|
|
Year ending December 31, 2010
|
|
|
1,680
|
|
|
|
55,762
|
|
Year ending December 31, 2011
|
|
|
948
|
|
|
|
53,939
|
|
Year ending December 31, 2012
|
|
|
196
|
|
|
|
51,333
|
|
Thereafter
|
|
|
10
|
|
|
|
372,325
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,933
|
|
|
$
|
582,345
|
|
|
|
|
|
|
|
|
|
|
The Company leases various equipment and real properties under
long-term operating leases. For the three months ended
March 31, 2008 and 2007, lease expense totaled $1,071,000
and $1,007,000, respectively. The lease agreements have various
remaining terms. Some agreements are renewable, at the
Companys option, for additional periods. It is expected,
in the ordinary course of business, that leases will be renewed
or replaced as they expire.
From time to time, the Company is involved in various lawsuits
arising in the normal course of business, including matters such
as those described below under Environmental, Health, and
Safety Matters. Liabilities related to such lawsuits are
recognized when the related costs are probable and
F-83
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
can be reasonably estimated. It is possible that
Managements estimates of the outcomes will change within
the next year due to uncertainties inherent in litigation and
settlement negotiations. In the opinion of management, the
ultimate resolution of the Companys litigation matters is
not expected to have a material adverse effect on the
accompanying consolidated financial statements. There can be no
assurance that managements beliefs or opinions with
respect to liability for potential litigation matters are
accurate.
Crude oil was discharged from the Companys refinery on
July 1, 2007 due to the short amount of time available to
shut down and secure the refinery in preparation for the flood
that occurred on June 30, 2007. As a result of the crude
oil discharge, two putative class action lawsuits (one federal
and one state) were filed seeking unspecified damages with class
certification under applicable law for all residents,
domiciliaries and property owners of Coffeyville, Kansas who
were impacted by the oil release.
The Company filed a motion to dismiss the federal suit for lack
of subject matter jurisdiction. On November 6, 2007, the
judge in the federal class action lawsuit granted the
Companys motion to dismiss for lack of subject matter
jurisdiction and no appeal was taken.
With respect to the state suit, the District Court of Montgomery
County, Kansas conducted an evidentiary hearing on the issue of
class certification on October 24 and 25, 2007 and ruled against
the class certification leaving only the original two
plaintiffs. To date no other lawsuits have been filed as a
result of flood related damages.
As a result of the crude oil discharge that occurred on
July 1, 2007, the Company entered into an administrative
order on consent (Consent Order) with the Environmental
Protection Agency (EPA) on July 10, 2007. As set forth in
the Consent Order, the EPA concluded that the discharge of oil
from the Companys refinery caused and may continue to
cause an imminent and substantial threat to the public health
and welfare. Pursuant to the Consent Order, the Company agreed
to perform specified remedial actions to respond to the
discharge of crude oil from the Companys refinery. The
Company is currently remediating the crude oil discharge and
expects its primary remedial actions to continue through May
2008 with continuing minor activities for a period thereafter.
The Company engaged experts to assess and test the areas
affected by the crude oil spill. The Company commenced a program
on July 19, 2007 to purchase approximately 330 homes and
other commercial properties in connection with the flood and the
crude oil release. Total costs recorded to date are
$13.4 million, which include costs incurred in 2007 of
$13.1 million and costs for the three months ended
March 31, 2008 of $0.3 million. Total costs recorded
related to personal property claims were approximately
$1.7 million, which were all recorded in 2007. Total costs
recorded related to estimated commercial property to be
purchased and associated claims were approximately
$3.6 million, which were all recorded in 2007. The total
amount of gross costs recorded for the three months ended
March 31, 2008 related to the residential and commercial
purchase and property claims program were approximately
$0.3 million. As the crude oil spill took place in the
second and third quarter of 2007, no costs associated with the
spill were incurred in the first quarter of 2007.
As of March 31, 2008, the total costs recorded for
obligations other than the purchase of homes, commercial
properties and related personal property claims approximated
$30.0 million. The Company has recorded as of
March 31, 2008 total costs (net of anticipated insurance
recoveries recorded of $21.4 million) associated with
remediation and third party property damage claims resolution of
approximately $27.3 million. The Company has not estimated
or accrued for, because management does not believe it is
probable that there will be any potential fines, penalties or
claims that may be imposed or brought by regulatory authorities
or possible additional damages arising from class action
lawsuits related to the flood.
F-84
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
It is difficult to estimate the ultimate cost of environmental
remediation resulting from the crude oil discharge or the cost
of third party property damage that the Company will ultimately
be required to pay. The costs and damages that the Company will
ultimately pay may be greater than the amounts described and
projected above. Such excess costs and damages could be material
to the consolidated financial statements.
The Company is seeking insurance coverage for this release and
for the ultimate costs for remediation, property damage claims,
cleanup, resolution of class action lawsuits, and other claims
brought by regulatory authorities. Although the Company believes
that it will recover substantial sums under its environmental
and liability insurance policies, the Company is not sure of the
ultimate amount or timing of such recovery because of the
difficulty inherent in projecting the ultimate resolution of the
Companys claims. The difference between what the Company
receives under its insurance policies compared to what has been
recorded and described above could be material to the
consolidated financial statements. The Company received
$10.0 million of insurance proceeds under its environmental
insurance policy in 2007.
Environmental,
Health, and Safety (EHS) Matters
CVR is subject to various stringent federal, state, and local
EHS rules and regulations. Liabilities related to EHS matters
are recognized when the related costs are probable and can be
reasonably estimated. Estimates of these costs are based upon
currently available facts, existing technology, site-specific
costs, and currently enacted laws and regulations. In reporting
EHS liabilities, no offset is made for potential recoveries.
Such liabilities include estimates of the Companys share
of costs attributable to potentially responsible parties which
are insolvent or otherwise unable to pay. All liabilities are
monitored and adjusted regularly as new facts emerge or changes
in law or technology occur.
CVR owns
and/or
operates manufacturing and ancillary operations at various
locations directly related to petroleum refining and
distribution and nitrogen fertilizer manufacturing. Therefore,
CVR has exposure to potential EHS liabilities related to past
and present EHS conditions at some of these locations.
Through an Administrative Order issued under the Resource
Conservation and Recovery Act, as amended (RCRA), CVR is a
potential party responsible for conducting corrective actions at
its Coffeyville, Kansas and Phillipsburg, Kansas facilities. In
2005, CRNF agreed to participate in the State of Kansas
Voluntary Cleanup and Property Redevelopment Program (VCPRP) to
address a reported release of urea ammonium nitrate (UAN) at the
Coffeyville UAN loading rack. As of March 31, 2008 and
December 31, 2007, environmental accruals of $7,713,000 and
$7,646,000, respectively, were reflected in the consolidated
balance sheets for probable and estimated costs for remediation
of environmental contamination under the RCRA Administrative
Order and the VCPRP, including amounts totaling $2,789,000 and
$2,802,000, respectively, included in other current liabilities.
The Companys accruals were determined based on an estimate
of payment costs through 2033, which scope of remediation was
arranged with the EPA and are discounted at the appropriate risk
free rates at March 31, 2008 and December 31, 2007,
respectively. The accruals include estimated closure and
post-closure costs of $1,580,000 and $1,549,000 for two
landfills at March 31, 2008 and December 31,
F-85
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
2007, respectively. The estimated future payments for these
required obligations are as follows (in thousands):
|
|
|
|
|
|
|
Amount
|
|
|
Nine months ending December 31, 2008
|
|
|
2,617
|
|
Year ending December 31, 2009
|
|
|
687
|
|
Year ending December 31, 2010
|
|
|
1,556
|
|
Year ending December 31, 2011
|
|
|
313
|
|
Year ending December 31, 2012
|
|
|
313
|
|
Thereafter
|
|
|
3,282
|
|
|
|
|
|
|
Undiscounted total
|
|
|
8,768
|
|
Less amounts representing interest at 3.13%
|
|
|
1,055
|
|
|
|
|
|
|
Accrued environmental liabilities at March 31, 2008
|
|
$
|
7,713
|
|
|
|
|
|
|
Management periodically reviews and, as appropriate, revises its
environmental accruals. Based on current information and
regulatory requirements, management believes that the accruals
established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of
sulfur in diesel and gasoline. The EPA has granted the Company a
petition for a technical hardship waiver with respect to the
date for compliance in meeting the sulfur-lowering standards.
CVR spent approximately $17 million in 2007,
$79 million in 2006 and $27 million in 2005 to comply
with the low-sulfur rules. CVR has spent $2 million in the
first three months of 2008 and based on information currently
available, anticipates spending approximately $17 million
in the last nine months of 2008 and $26 million in 2009 to
comply with the low-sulfur rules. The entire amounts are
expected to be capitalized.
Environmental expenditures are capitalized when such
expenditures are expected to result in future economic benefits.
For the three month periods ended March 31, 2008 and 2007,
capital expenditures were $15,473,000 and $50,687,000,
respectively, and were incurred to improve the environmental
compliance and efficiency of the operations.
CVR believes it is in substantial compliance with existing EHS
rules and regulations. There can be no assurance that the EHS
matters described above or other EHS matters which may develop
in the future will not have a material adverse effect on the
Companys business, financial condition, or results of
operations.
|
|
(13)
|
Derivative
Financial Instruments
|
Loss on derivatives consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Realized loss on swap agreements
|
|
$
|
(21,516
|
)
|
|
$
|
(8,534
|
)
|
Unrealized loss on swap agreements
|
|
|
(13,907
|
)
|
|
|
(119,704
|
)
|
Realized loss on other agreements
|
|
|
(7,993
|
)
|
|
|
(2,763
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
1,157
|
|
|
|
(5,332
|
)
|
Realized gain on interest rate swap agreements
|
|
|
522
|
|
|
|
1,241
|
|
Unrealized loss on interest rate swap agreements
|
|
|
(6,134
|
)
|
|
|
(1,867
|
)
|
|
|
|
|
|
|
|
|
|
Total loss on derivatives
|
|
$
|
(47,871
|
)
|
|
$
|
(136,959
|
)
|
|
|
|
|
|
|
|
|
|
F-86
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
CVR is subject to price fluctuations caused by supply
conditions, weather, economic conditions, and other factors and
to interest rate fluctuations. To manage price risk on crude oil
and other inventories and to fix margins on certain future
production, CVR may enter into various derivative transactions.
In addition, CALLC, as further described below, entered into
certain commodity derivate contracts and an interest rate swap
as required by the long-term debt agreements.
CVR has adopted SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities
. SFAS 133
imposes extensive record-keeping requirements in order to
designate a derivative financial instrument as a hedge. CVR
holds derivative instruments, such as exchange-traded crude oil
futures, certain over-the-counter forward swap agreements and
interest rate swap agreements, which it believes provide an
economic hedge on future transactions, but such instruments are
not designated as hedges. Gains or losses related to the change
in fair value and periodic settlements of these derivative
instruments are classified as loss on derivatives, net in the
Consolidated Statements of Operations.
At March 31, 2008, CVRs Petroleum Segment held
commodity derivative contracts (swap agreements) for the period
from July 1, 2005 to June 30, 2010 with a related
party (see Note 15, Related Party
Transactions). The swap agreements were originally
executed by CALLC on June 16, 2005 and were required under
the terms of the Companys long-term debt agreements. The
notional quantities on the date of execution were
100,911,000 barrels of crude oil, 1,889,459,250 gallons of
heating oil and 2,348,802,750 gallons of unleaded gasoline. The
swap agreements were executed at the prevailing market rate at
the time of execution and management believes the swap
agreements provide an economic hedge on future transactions. At
March 31, 2008 the notional open amounts under the swap
agreements were 36,190,000 barrels of crude oil,
759,990,000 gallons of heating oil and 759,990,000 gallons of
unleaded gasoline. These positions resulted in unrealized losses
for the three months ended March 31, 2008 and 2007 of
$13,907,000 and $119,704,000, respectively. The Petroleum
Segment recorded $21,516,000 and $8,534,000 in realized losses
on these swap agreements for the three month periods ended
March 31, 2008 and 2007, respectively.
The Petroleum Segment also recorded mark-to-market net losses,
in loss on derivatives, net exclusive of the swap agreements
described above and the interest rate swaps described in the
following paragraph, of $6,836,000 and $8,095,000, for the three
month periods ended March 31, 2008 and 2007, respectively.
All of the activity related to the commodity derivative
contracts is reported in the Petroleum Segment.
At March 31, 2008, CRLLC held derivative contracts known as
interest rate swap agreements that converted CRLLCs
floating-rate bank debt into 4.195% fixed-rate debt on a
notional amount of $325,000,000. Half of the agreements are held
with a related party (as described in Note 15,
Related Party Transactions), and the other half are
held with a financial institution that is a lender under
CRLLCs long-term debt agreements. The swap agreements
carry the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Fixed
|
|
Period Covered
|
|
Amount
|
|
|
Interest Rate
|
|
|
June 30, 2007 to March 31, 2008
|
|
|
325 million
|
|
|
|
4.195
|
%
|
March 31, 2008 to March 30, 2009
|
|
|
250 million
|
|
|
|
4.195
|
%
|
March 31, 2009 to March 30, 2010
|
|
|
180 million
|
|
|
|
4.195
|
%
|
March 31, 2010 to June 29, 2010
|
|
|
110 million
|
|
|
|
4.195
|
%
|
CVR pays the fixed rates listed above and receives a floating
rate based on three-month LIBOR rates, with payments calculated
on the notional amounts listed above. The notional amounts do
not represent actual amounts exchanged by the parties but
instead represent the amounts on which the contracts are based.
The swap is settled quarterly and marked-to-market at each
reporting date, and all unrealized gains and losses are
currently recognized in income. Transactions related to the
interest
F-87
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
rate swap agreements were not allocated to the Petroleum or
Nitrogen Fertilizer segments. Mark-to-market net losses on
derivatives and quarterly settlements were $5,612,000 and
$626,000 for the three month periods ended March 31, 2008
and 2007, respectively.
|
|
(14)
|
Fair Value
Measurements
|
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
. This statement established a
single authoritative definition of fair value when accounting
rules require the use of fair value, set out a framework for
measuring fair value, and required additional disclosures about
fair value measurements. SFAS 157 clarifies that fair value
is an exit price, representing the amount that would be received
to sell an asset or paid to transfer a liability in an orderly
transaction between market participants.
The Company adopted SFAS 157 on January 1, 2008 with
the exception of nonfinancial assets and nonfinancial
liabilities that were deferred by FASB Staff Position
157-2
as
discussed in Note 2 to the Condensed Consolidated Financial
Statements. As of March 31, 2008, the Company has not
applied SFAS 157 to goodwill and intangible assets in
accordance with FASB Staff Position
157-2.
SFAS 157 discusses valuation techniques, such as the market
approach (prices and other relevant information generated by
market conditions involving identical or comparable assets or
liabilities), the income approach (techniques to convert future
amounts to single present amounts based on market expectations
including present value techniques and option-pricing), and the
cost approach (amount that would be required to replace the
service capacity of an asset which is often referred to as
replacement cost). SFAS 157 utilizes a fair value hierarchy
that prioritizes the inputs to valuation techniques used to
measure fair value into three broad levels. The following is a
brief description of those three levels:
|
|
|
|
|
Level 1 Quoted prices in active market for
identical assets and liabilities
|
|
|
|
Level 2 Other significant observable inputs
(including quoted prices in active markets for similar assets or
liabilities)
|
|
|
|
Level 3 Significant unobservable inputs
(including the Companys own assumptions in determining the
fair value)
|
The following table sets forth the assets and liabilities
measured at fair value on a recurring basis, by input level, as
of March 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Cash Flow Swap
|
|
|
|
|
|
$
|
(13,907
|
)
|
|
|
|
|
|
$
|
(13,907
|
)
|
Interest Rate Swap
|
|
|
|
|
|
|
(6,134
|
)
|
|
|
|
|
|
|
(6,134
|
)
|
Other Derivative Agreements
|
|
|
|
|
|
|
1,157
|
|
|
|
|
|
|
|
1,157
|
|
The Companys derivative contracts giving rise to assets or
liabilities under Level 2 are valued using pricing models
based on other significant observable inputs.
|
|
(15)
|
Related Party
Transactions
|
GS Capital Partners V Fund, L.P. and related entities (GS) and
Kelso Investment Associates VII, L.P. and related entity (Kelso)
are majority owners of CVR.
On June 24, 2005, CALLC entered into management services
agreements with each of GS and Kelso pursuant to which GS and
Kelso agreed to provide CALLC with managerial and advisory
services. In consideration for these services, an annual fee of
$1.0 million was paid to each of GS and Kelso, plus
reimbursement for any out-of-pocket expenses. The agreements
terminated upon consummation of CVRs initial public
offering on October 26, 2007. Relating to the agreements,
$0 and $538,000 were expensed in selling, general, and
administrative expenses (exclusive of depreciation and
amortization)
F-88
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
for the three months ended March 31, 2008 and
March 31, 2007, respectively. The Company paid a one-time
fee of $5.0 million to each of GS and Kelso by reason of
the termination of the agreements on October 26, 2007.
CALLC entered into certain crude oil, heating oil and gasoline
swap agreements with a subsidiary of GS. Additional swap
agreements with this subsidiary of GS were entered into on
June 16, 2005, with an expiration date of June 30,
2010 (as described in Note 13, Derivative Financial
Instruments). These agreements were assigned to
Coffeyville Resources LLC, a subsidiary of CVR. Losses totaling
$35,423,000 and $128,238,000 were recognized related to these
swap agreements for the three months ended March 31, 2008
and 2007, respectively, and are reflected in loss on
derivatives, net in the Consolidated Statements of Operations.
In addition, the Consolidated Balance Sheet at March 31,
2008 and December 31, 2007 includes liabilities of
$294,984,000 and $262,415,000, respectively, included in current
payable to swap counterparty and $76,411,000 and $88,230,000,
respectively, included in long-term payable to swap counterparty.
On June 26, 2007, the Company entered into a letter
agreement with the subsidiary of GS to defer a
$45.0 million payment owed on July 8, 2007 to the GS
subsidiary for the period ended September 30, 2007 until
August 7, 2007. Interest accrued on the deferred amount of
$45.0 million at the rate of LIBOR plus 3.25%.
As a result of the flood and the related temporary cessation of
business operations, the Company entered into a subsequent
letter agreement on July 11, 2007 in which the GS
subsidiary agreed to defer an additional $43.7 million of
the balance owed for the period ending June 30, 2007. This
deferral was entered into on the conditions that each of GS and
Kelso agreed to guarantee one half of the payment and that
interest accrued on the $43.7 million from July 9,
2007 to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter
agreement in which the GS subsidiary agreed to defer to
September 7, 2007 both the $45.0 million payment due
August 7, 2007 along with accrued interest and the
$43.7 million payment due July 25, 2007 with the
related accrued interest. These payments were deferred on the
conditions that GS and Kelso each agreed to guarantee one half
of the payments. Additionally, interest accrues on the amount
from July 26, 2007 to the date of payment at the rate of
LIBOR plus 1.50%.
On August 23, 2007, the Company entered into an additional
letter agreement in which the GS subsidiary agreed to further
defer both deferred payment amounts and the related accrued
interest with payment being due on January 31, 2008.
Additionally, it was further agreed that the $35 million
payment to settle hedged volumes through August 15, 2007
would be deferred with payment being due on January 31,
2008. Interest accrues on all deferral amounts through the
payment due date at LIBOR plus 1.50%. GS and Kelso have each
agreed to guarantee one half of all payment deferrals. The GS
subsidiary further agreed to defer these payment amounts to
August 31, 2008 if the Company closed an initial public
offering prior to January 31, 2008. Due to the consummation
of the initial public offering on October 26, 2007, these
payment amounts are now deferred until August 31, 2008;
however, the company is required to use 37.5% of its
consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferral amounts. As of
March 31, 2008 the Company was not required to pay any
portion of the deferred amount.
These deferred payment amounts are included in the Consolidated
Balance Sheet at March 31, 2008 in current payable to swap
counterparty. The deferred balance owed to GS, excluding accrued
interest payable, totalled $123.7 million at March 31,
2008. Approximately $4,874,000 of accrued interest payable
related to the deferred payments is included in other current
liabilities at March 31, 2008.
F-89
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
On June 30, 2005, CALLC entered into three interest-rate
swap agreements with the same subsidiary of GS (as described in
Note 13, Derivative Financial Instruments).
Losses totaling $2,813,000 and $313,000 were recognized related
to these swap agreements for the three months ended
March 31, 2008 and 2007, respectively, and are reflected in
loss on derivatives, net in the Consolidated Statements of
Operations. In addition, the Consolidated Balance Sheet at
March 31, 2008 and December 31, 2007 includes
$1,778,000 and $371,000, respectively, in other current
liabilities and $2,223,000 and $557,000, respectively, in other
long-term liabilities related to the same agreements.
Effective December 30, 2005, the Company entered into a
crude oil supply agreement with a subsidiary of GS (Supplier).
Under the agreement, the parties agreed to negotiate the cost of
each barrel of crude oil to be purchased from a third party, and
CVR agreed to pay Supplier a fixed supply service fee per barrel
over the negotiated cost of each barrel of crude purchased. The
cost is adjusted further using a spread adjustment calculation
based on the time period the crude oil is estimated to be
delivered to the refinery, other market conditions, and other
factors deemed appropriate. The initial term of the agreement
was to December 31, 2006. CVR and Supplier agreed to extend
the term of the supply agreement for an additional 12 month
period, from January 1, 2007 through December 31,
2007, and in connection with the extension amended certain terms
and conditions of the supply agreement. On December 31,
2007, CVR and supplier entered into an amended and restated
crude oil supply agreement. The terms of the agreement remained
substantially the same. $241,000 and $360,000 were recorded on
the consolidated balance sheet at March 31, 2008 and
December 31, 2007, respectively, in prepaid expenses and
other current assets for prepayment of crude oil. In addition,
$62,039,000 and $43,773,000 were recorded in inventory and
$27,909,000 and $42,666,000 were recorded in accounts payable at
March 31, 2008 and December 31, 2007, respectively.
Expenses associated with this agreement, included in cost of
product sold (exclusive of depreciation and amortization) for
the three month period ended March 31, 2008 and 2007
totaled $766,213,000 and $176,307,000, respectively. Interest
expense associated with this agreement for the three month
period ended March 31, 2008 and 2007 totaled $14,000 and
$(1,029,000), respectively.
As a result of the refinery turnaround in early 2007, CVR needed
to delay the processing of quantities of crude oil that it
purchased from various small independent producers. In order to
facilitate this anticipated delay, CVR entered into a purchase,
storage and sale agreement for gathered crude oil, dated
March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant
to the terms of the agreement, J. Aron agreed to purchase
gathered crude oil from CVR, store the gathered crude oil and
sell CVR the gathered crude oil on a forward basis.
CVR measures segment profit as operating income for Petroleum
and Nitrogen Fertilizer, CVRs two reporting segments,
based on the definitions provided in SFAS No. 131,
Disclosures about Segments of an Enterprise and Related
Information
. All operations of the segments are located
within the United States.
Petroleum
Principal products of the Petroleum Segment are refined fuels,
propane, and petroleum refining by-products including pet coke.
CVR sells the pet coke to the Partnership for use in the
manufacturing of nitrogen fertilizer at the adjacent nitrogen
fertilizer plant. For CVR, a per-ton transfer price is used to
record intercompany sales on the part of the Petroleum Segment
and corresponding intercompany cost of product sold (exclusive
of depreciation and amortization) for the Nitrogen Fertilizer
Segment. The per ton transfer price paid, pursuant to the coke
supply agreement that became effective October 24, 2007, is
based on the lesser of a coke price derived from the priced
received by the fertilizer segment for UAN (subject to a UAN
based price ceiling and floor) and a coke price index for
F-90
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
pet coke. Prior to October 25, 2007 intercompany sales were
based upon a price of $15 per ton. The intercompany transactions
are eliminated in the Other Segment. Intercompany sales included
in petroleum net sales were $2,806,000 and $580,000 for the
three months ended March 31, 2008 and 2007, respectively.
Intercompany cost of product sold (exclusive of depreciation and
amortization) for the hydrogen sales described below under
Nitrogen Fertilizer was $5,291,000 and
$2,829,000 for the three months ended March 31, 2008 and
2007, respectively.
Nitrogen
Fertilizer
The principal product of the Nitrogen Fertilizer Segment is
nitrogen fertilizer. Intercompany cost of product sold
(exclusive of depreciation and amortization) for the coke
transfer described above was $2,545,000 and $850,000 for the
three months ended March 31, 2008 and 2007, respectively.
Beginning in 2008, the Nitrogen Fertilizer Segment made a change
as to the classification of intercompany hydrogen sales to the
Petroleum Segment. In 2008, these amounts are reflected as
Net Sales for the fertilizer plant. Prior to 2008,
the Nitrogen Fertilizer Segment reflected these transactions as
a reduction of cost of product sold (exclusive of depreciation
and amortization). For the quarters ended March 31, 2008
and 2007, the net sales generated from intercompany hydrogen
sales were $5,291,000 and $2,829,000, respectively. As noted
above, the net sales of $2,829,000 were included as a reduction
to the cost of product sold (exclusive of depreciation and
amortization) for 2007. As these intercompany sales are
eliminated, there is no financial statement impact on the
consolidated financial statements.
F-91
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
Other
Segment
The Other Segment reflects intercompany eliminations, cash and
cash equivalents, all debt related activities, income tax
activities and other corporate activities that are not allocated
to the operating segments.
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in thousands)
|
|
|
Net sales
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,168,500
|
|
|
$
|
352,488
|
|
Nitrogen Fertilizer
|
|
|
62,600
|
|
|
|
38,575
|
|
Intersegment eliminations
|
|
|
(8,097
|
)
|
|
|
(580
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,223,003
|
|
|
$
|
390,483
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and
amortization) Petroleum
|
|
$
|
1,035,085
|
|
|
$
|
298,460
|
|
Nitrogen Fertilizer
|
|
|
8,945
|
|
|
|
6,060
|
|
Intersegment eliminations
|
|
|
(7,836
|
)
|
|
|
(850
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,036,194
|
|
|
$
|
303,670
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization) Petroleum
|
|
$
|
40,290
|
|
|
$
|
96,674
|
|
Nitrogen Fertilizer
|
|
|
20,266
|
|
|
|
16,738
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
60,556
|
|
|
$
|
113,412
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
5,533
|
|
|
$
|
|
|
Nitrogen Fertilizer
|
|
|
(17
|
)
|
|
|
|
|
Other
|
|
|
247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,763
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
14,877
|
|
|
$
|
9,794
|
|
Nitrogen Fertilizer
|
|
|
4,477
|
|
|
|
4,394
|
|
Other
|
|
|
281
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
19,635
|
|
|
$
|
14,235
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
63,618
|
|
|
$
|
(63,468
|
)
|
Nitrogen Fertilizer
|
|
|
26,017
|
|
|
|
9,319
|
|
Other
|
|
|
(2,277
|
)
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
87,358
|
|
|
$
|
(53,984
|
)
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
22,541
|
|
|
$
|
106,501
|
|
Nitrogen Fertilizer
|
|
|
2,817
|
|
|
|
402
|
|
Other
|
|
|
798
|
|
|
|
460
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
26,156
|
|
|
$
|
107,363
|
|
|
|
|
|
|
|
|
|
|
F-92
CVR ENERGY, INC.
AND SUBSIDIARIES
Notes to the
Condensed Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,352,961
|
|
|
$
|
1,277,124
|
|
Nitrogen Fertilizer
|
|
|
496,326
|
|
|
|
446,763
|
|
Other
|
|
|
74,304
|
|
|
|
144,469
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,923,591
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
42,806
|
|
|
$
|
42,806
|
|
Nitrogen Fertilizer
|
|
|
40,969
|
|
|
|
40,969
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
83,775
|
|
|
$
|
83,775
|
|
|
|
|
|
|
|
|
|
|
On June 13, 2008, the Company announced that the managing
general partner of the Partnership had decided to postpone
indefinitely the Partnerships initial public offering. The
Partnership has notified the SEC that it intends to withdraw the
registration statement it filed in February 2008.
F-93
No dealer, salesperson or
other person is authorized to give any information or to
represent anything not contained in this prospectus. You must
not rely on any unauthorized information or representations.
This prospectus is an offer to sell only the shares of common
stock offered hereby, but only under circumstances where it is
lawful to do so. The information contained in this prospectus is
current only as of its date.
TABLE OF CONTENTS
10,000,000 Shares
CVR Energy, Inc.
Common Stock
PROSPECTUS
Goldman, Sachs &
Co.
Deutsche Bank
Securities
Citi
Credit Suisse
PART II
INFORMATION NOT
REQUIRED IN PROSPECTUS
|
|
Item 13.
|
Other Expenses
of Issuance and Distribution.
|
The following table sets forth the costs and expenses to be paid
by the Registrant in connection with the sale of the shares of
common stock being registered hereby. All amounts are estimates
except for the SEC registration fee, the Financial Industry
Regulatory Authority (FINRA) filing fee.
|
|
|
|
|
SEC registration fee
|
|
$
|
11,530
|
|
FINRA filing fee
|
|
$
|
29,837
|
|
Accounting fees and expenses
|
|
|
|
|
Legal fees and expenses
|
|
|
|
|
Printing and engraving expenses
|
|
|
|
|
Transfer agent and registrar fees and expenses
|
|
|
|
|
Miscellaneous expenses
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
|
|
|
|
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
Section 145 of the Delaware General Corporation Law
authorizes a court to award, or a corporations board of
directors to grant, indemnity to directors and officers in terms
sufficiently broad to permit such indemnification under certain
circumstances for liabilities (including reimbursement for
expenses incurred) arising under the Securities Act of 1933, as
amended (the Securities Act).
As permitted by the Delaware General Corporation Law, the
Registrants Certificate of Incorporation includes a
provision that eliminates the personal liability of its
directors for monetary damages for breach of fiduciary duty as a
director, except for liability:
|
|
|
|
|
for any breach of the 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.
|
As permitted by the Delaware General Corporation Law, the
Registrants Bylaws provide that:
|
|
|
|
|
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.
|
The Registrant may enter into Indemnity Agreements with each of
its current directors and officers to give these directors and
officers additional contractual assurances regarding the scope
of the indemnification set forth in the Registrants
Certificate of Incorporation and to provide additional
procedural protections. At present, there is no pending
litigation or proceeding involving a director, officer or
employee of the Registrant regarding which indemnification is
sought, nor is the Registrant aware of any threatened litigation
that may result in claims for indemnification.
II-1
The indemnification provisions in the Registrants
Certificate of Incorporation and Bylaws and any Indemnity
Agreements entered into between the Registrant and each of its
directors and officers may be sufficiently broad to permit
indemnification of the Registrants directors and officers
for liabilities arising under the Securities Act.
CVR Energy, Inc. and its subsidiaries are covered by liability
insurance policies which indemnify their directors and officers
against loss arising from claims by reason of their legal
liability for acts as such directors, officers or trustees,
subject to limitations and conditions as set forth in the
policies.
The underwriting agreement to be entered into among the company,
the selling stockholders and the underwriters will contain
indemnification and contribution provisions.
|
|
Item 15.
|
Recent Sales
of Unregistered Securities.
|
We issued 100 shares of common stock to Coffeyville
Acquisition LLC in September 2006 for nominal consideration. The
issuance was exempt from registration in accordance with
Section 4(2) of the Securities Act of 1933, as amended. We
issued 247,471 shares of common stock to our chief
executive officer in October 2007. In exchange for shares he
owned in Coffeyville Nitrogen Fertilizers, Inc. and Coffeyville
Refining and Marketing Holding Holdings, Inc. The issuance was
exempt from registration in accordance with Rule 701 under
the Securities Act of 1933, as amended.
|
|
Item 16.
|
Exhibits and
Financial Statement Schedules.
|
(a) The exhibits to this Registration Statement are listed
on the Exhibit Index page hereof, which is incorporated by
reference in this Item 16.
(b) The financial statement schedules are omitted because
they are inapplicable or the requested information is shown in
the consolidated financial statements of CVR Energy, Inc. or
related notes thereto.
Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and
controlling persons of the Registrant pursuant to the provisions
described in Item 14 above, or otherwise, the Registrant
has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public
policy as expressed in the Securities Act and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
Registrant of expenses incurred or paid by a director, officer
or controlling person of the Registrant in the successful
defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the
securities being registered, the Registrant will, unless in the
opinion of its counsel the matter has been settled by
controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and
will be governed by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the
Securities Act, the information omitted from the form of
prospectus filed as part of this Registration Statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the Registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this Registration Statement as
of the time it was declared effective; and
(2) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration
statement relating to the securities offered therein, and the
offering of such securities at the time shall be deemed to be
the initial bona fide offering thereof.
II-2
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
Registrant has duly caused this Registration Statement to be
signed on its behalf by the undersigned, thereunto duly
authorized in Sugar Land, State of Texas, on this 19th day of
June 2008.
CVR ENERGY, INC.
John J. Lipinski
Chief Executive Officer and President
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints John J. Lipinski, James
T. Rens and Edmund S. Gross, and each of them, his or her true
and lawful attorneys-in-fact and agents with full powers of
substitution and resubstitution, for him or her and in his or
her name, place and stead, in any and all capacities, to sign
any or all amendments to this Registration Statement, including
post-effective amendments and registration statements filed
pursuant to Rule 462(b) and otherwise, and to file the
same, with all exhibits thereto, and other documents in
connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and
each of them, full power and authority to do and perform each
and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as
he or she might or could do in person, and hereby ratifies and
confirms all his or her said attorneys-in-fact and agents, or
any of them, or his or her substitute or substitutes may
lawfully do or cause to be done by virtue thereof.
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons
in the capacities and on the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/
John
J. Lipinski
John
J. Lipinski
|
|
Chief Executive Officer, President and
Director (Principal Executive Officer)
|
|
June 19, 2008
|
|
|
|
|
|
/s/
James
T. Rens
James
T. Rens
|
|
Chief Financial Officer (Principal
Financial and Accounting Officer)
|
|
June 19, 2008
|
|
|
|
|
|
/s/
Scott
L. Lebovitz
Scott
L. Lebovitz
|
|
Director
|
|
June 19, 2008
|
|
|
|
|
|
/s/
Regis
B. Lippert
Regis
B. Lippert
|
|
Director
|
|
June 19, 2008
|
|
|
|
|
|
/s/
George
E. Matelich
George
E. Matelich
|
|
Director
|
|
June 19, 2008
|
|
|
|
|
|
/s/
Steve
A. Nordaker
Steve
A. Nordaker
|
|
Director
|
|
June 19, 2008
|
II-3
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/
Stanley
de J. Osborne
Stanley
de J. Osborne
|
|
Director
|
|
June 19, 2008
|
|
|
|
|
|
/s/
Kenneth
A. Pontarelli
Kenneth
A. Pontarelli
|
|
Director
|
|
June 19, 2008
|
|
|
|
|
|
/s/
Mark
Tomkins
Mark
Tomkins
|
|
Director
|
|
June 19, 2008
|
II-4
EXHIBIT INDEX
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement.
|
|
3
|
.1**
|
|
Amended and Restated Certificate of Incorporation of CVR Energy,
Inc. (filed as Exhibit 10.1 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
3
|
.2**
|
|
Amended and Restated Bylaws of CVR Energy, Inc. (filed as
Exhibit 10.2 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
4
|
.1**
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to
the Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
5
|
.1*
|
|
Form of opinion of Fried, Frank, Harris, Shriver &
Jacobson LLP.
|
|
10
|
.1**
|
|
Second Amended and Restated Credit and Guaranty Agreement, dated
as of December 28, 2006, among Coffeyville Resources, LLC
and the other parties thereto (filed as Exhibit 10.1 to the
Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.1.1**
|
|
First Amendment to Second Amended and Restated Credit and
Guaranty Agreement, dated as of August 23, 2007, among
Coffeyville Resources, LLC and the other parties thereto (filed
as Exhibit 10.1.1 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.2**
|
|
Amended and Restated First Lien Pledge and Security Agreement,
dated as of December 28, 2006, among Coffeyville Resources,
LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc.,
Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen
Fertilizers, Inc., Coffeyville Crude Transportation, Inc.,
Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC,
Coffeyville Resources Refining & Marketing, LLC,
Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville
Resources Crude Transportation, LLC and Coffeyville Resources
Terminal, LLC, as grantors, and Credit Suisse, as collateral
agent (filed as Exhibit 10.2 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.3**
|
|
Swap agreements with J. Aron & Company (filed as
Exhibit 10.5 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.3.1**
|
|
Letter agreements between Coffeyville Resources, LLC and J.
Aron & Company, dated as of June 26, 2007,
July 11, 2007, July 26, 2007 and August 23, 2007
(filed as Exhibit 10.5.1 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.4**
|
|
License Agreement For Use of the Texaco Gasification Process,
Texaco Hydrogen Generation Process, and Texaco Gasification
Power Systems, dated as of May 30, 1997 by and between
Texaco Development Corporation and Farmland Industries, Inc., as
amended (filed as Exhibit 10.4 to the Companys
Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.5**
|
|
Amended and Restated
On-Site
Product Supply Agreement dated as of June 1, 2005, between
The Linde Group (f/k/a The BOC Group, Inc.) and Coffeyville
Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6
to the Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.6**
|
|
Amended and Restated Crude Oil Supply Agreement, dated as of
December 31, 2007, between J. Aron & Company and
Coffeyville Resources Refining and Marketing, LLC (filed as
Exhibit 10.1 to the Companys Current Report on
Form 8-K,
filed on January 7, 2008 and incorporated by reference
herein).
|
|
10
|
.7**
|
|
Pipeline Construction, Operation and Transportation Commitment
Agreement, dated February 11, 2004, as amended, between
Plains Pipeline, L.P. and Coffeyville Resources
Refining & Marketing, LLC (filed as Exhibit 10.14
to the Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.8**
|
|
Electric Services Agreement dated January 13, 2004, between
Coffeyville Resources Nitrogen Fertilizers, LLC and the City of
Coffeyville, Kansas (filed as Exhibit 10.15 to the
Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.9**
|
|
Purchase, Storage and Sale Agreement for Gathered Crude, dated
as of March 20, 2007, between J. Aron & Company
and Coffeyville Resources Refining & Marketing, LLC
(filed as Exhibit 10.22 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.10**
|
|
Stockholders Agreement of CVR Energy, Inc., dated as of
October 16, 2007, by and among CVR Energy, Inc.,
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC (filed as Exhibit 10.20 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.11**
|
|
Registration Rights Agreement, dated as of October 16,
2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC
and Coffeyville Acquisition II LLC (filed as
Exhibit 10.21 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.12**
|
|
Management Registration Rights Agreement, dated as of
October 24, 2007, by and between CVR Energy, Inc. and John
J. Lipinski (filed as Exhibit 10.27 to the Companys
Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.13**
|
|
Stock Purchase Agreement, dated as of May 15, 2005 by and
between Coffeyville Group Holdings, LLC and Coffeyville
Acquisition LLC (filed as Exhibit 10.23 to the
Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.13.1**
|
|
Amendment No. 1 to the Stock Purchase Agreement, dated as
of June 24, 2005 by and between Coffeyville Group Holdings,
LLC and Coffeyville Acquisition LLC (filed as
Exhibit 10.23.1 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.13.2**
|
|
Amendment No. 2 to the Stock Purchase Agreement, dated as
of July 25, 2005 by and between Coffeyville Group Holdings,
LLC and Coffeyville Acquisition LLC (filed as
Exhibit 10.23.2 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.14**
|
|
First Amended and Restated Agreement of Limited Partnership of
CVR Partners, LP, dated as of October 24, 2007, by and
among CVR GP, LLC, CVR Special GP, LLC and Coffeyville
Resources, LLC (filed as Exhibit 10.4 to the Companys
Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.15**
|
|
Coke Supply Agreement, dated as of October 25, 2007, by and
between Coffeyville Resources Refining & Marketing,
LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed
as Exhibit 10.5 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.16**
|
|
Cross Easement Agreement, dated as of October 25, 2007, by
and between Coffeyville Resources Refining &
Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers,
LLC (filed as Exhibit 10.6 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.17**
|
|
Environmental Agreement, dated as of October 25, 2007, by
and between Coffeyville Resources Refining &
Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers,
LLC (filed as Exhibit 10.7 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.17.1**
|
|
Supplement to Environmental Agreement, dated as of
February 15, 2008, by and between Coffeyville Resources
Refining and Marketing, LLC and Coffeyville Resources Nitrogen
Fertilizers, LLC (filed as Exhibit 10.17.1 to the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.18**
|
|
Feedstock and Shared Services Agreement, dated as of
October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources
Nitrogen Fertilizers, LLC (filed as Exhibit 10.8 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.19**
|
|
Raw Water and Facilities Sharing Agreement, dated as of
October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources
Nitrogen Fertilizers, LLC (filed as Exhibit 10.9 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.20**
|
|
Services Agreement, dated as of October 25, 2007, by and
among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and
CVR Energy, Inc. (filed as Exhibit 10.10 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.21**
|
|
Omnibus Agreement, dated as of October 24, 2007 by and
among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR
Partners, LP (filed as Exhibit 10.11 to the Companys
Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.22**
|
|
Contribution, Conveyance and Assumption Agreement, dated as of
October 24, 2007, by and among Coffeyville Resources, LLC,
CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP (filed as
Exhibit 10.26 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.23**
|
|
Registration Rights Agreement, dated as of October 24,
2007, by and among CVR Partners, LP, CVR Special GP, LLC and
Coffeyville Resources, LLC (filed as Exhibit 10.24 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.24**
|
|
Amended and Restated Employment Agreement, dated as of
January 1, 2008, by and between CVR Energy, Inc. and John
J. Lipinski (filed as Exhibit 10.24 to the Companys
Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.25**
|
|
Amended and Restated Employment Agreement, dated as of
December 29, 2007, by and between CVR Energy, Inc. and
Stanley A. Riemann (filed as Exhibit 10.25 to the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.26**
|
|
Amended and Restated Employment Agreement, dated as of
December 29, 2007, by and between CVR Energy, Inc. and
James T. Rens (filed as Exhibit 10.26 to the Companys
Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.27**
|
|
Employment Agreement, dated as of October 23, 2007, by and
between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as
Exhibit 10.27 to the Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.27.1**
|
|
First Amendment to Employment Agreement, dated as of
November 30, 2007, by and between CVR Energy, Inc. and
Daniel J. Daly, Jr. (filed as Exhibit 10.27.1 to the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.28**
|
|
Amended and Restated Employment Agreement, dated as of
December 29, 2007, by and between CVR Energy, Inc. and
Robert W. Haugen (filed as Exhibit 10.28 to the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.29**
|
|
CVR Energy, Inc. 2007 Long Term Incentive Plan (filed as
Exhibit 10.13 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.29.1**
|
|
Form of Nonqualified Stock Option Agreement (filed as
Exhibit 10.33.1 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.29.2**
|
|
Form of Director Stock Option Agreement (filed as
Exhibit 10.33.2 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.29.3**
|
|
Form of Director Restricted Stock Agreement (filed as
Exhibit 10.33.3 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.30**
|
|
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
I), as amended (filed as Exhibit 10.3 to the Companys
Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.31**
|
|
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
II) (filed as Exhibit 10.12 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.32**
|
|
Stockholders Agreement of Coffeyville Nitrogen Fertilizer, Inc.,
dated as of March 9, 2007, by and among Coffeyville
Nitrogen Fertilizers, Inc., Coffeyville Acquisition LLC and John
J. Lipinski (filed as Exhibit 10.17 to the Companys
Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.33**
|
|
Stockholders Agreement of Coffeyville Refining &
Marketing Holdings, Inc., dated as of August 22, 2007, by
and among Coffeyville Refining & Marketing Holdings,
Inc., Coffeyville Acquisition LLC and John J. Lipinski (filed as
Exhibit 10.18 to the Companys Original Registration
Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.34**
|
|
Subscription Agreement, dated as of March 9, 2007, by
Coffeyville Nitrogen Fertilizers, Inc. and John J. Lipinski
(filed as Exhibit 10.19 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.35**
|
|
Subscription Agreement, dated as of August 22, 2007, by
Coffeyville Refining & Marketing Holdings, Inc. and
John J. Lipinski (filed as Exhibit 10.20 to the
Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated herein by reference).
|
|
10
|
.36**
|
|
Amended and Restated Recapitalization Agreement, dated as of
October 16, 2007, by and among Coffeyville Acquisition LLC,
Coffeyville Refining & Marketing Holdings, Inc.,
Coffeyville Refining & Marketing, Inc., Coffeyville
Nitrogen Fertilizers, Inc. and CVR Energy, Inc. (filed as
Exhibit 10.3 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.37**
|
|
Subscription Agreement, dated as of October 16, 2007, by
and between CVR Energy, Inc. and John J. Lipinski (filed as
Exhibit 10.21 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.38**
|
|
Redemption Agreement, dated as of October 16, 2007, by
and among Coffeyville Acquisition LLC and the Redeemed Parties
signatory thereto (filed as Exhibit 10.19 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.39**
|
|
Third Amended and Restated Limited Liability Company Agreement
of Coffeyville Acquisition LLC, dated as of October 16,
2007 (filed as Exhibit 10.4 to the Companys Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.39.1**
|
|
Amendment No. 1 to the Third Amended and Restated Limited
Liability Company Agreement of Coffeyville Acquisition LLC,
dated as of October 16, 2007 (filed as Exhibit 10.15
to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.40**
|
|
First Amended and Restated Limited Liability Company Agreement
of Coffeyville Acquisition II LLC, dated as of
October 16, 2007 (filed as Exhibit 10.16 to the
Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.40.1**
|
|
Amendment No. 1 to the First Amended and Restated Limited
Liability Company Agreement of Coffeyville Acquisition II
LLC, dated as of October 16, 2007 (filed as
Exhibit 10.17 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.41**
|
|
Amended and Restated Limited Liability Company Agreement of
Coffeyville Acquisition III LLC, dated as of
February 15, 2008 (filed as Exhibit 10.41 to the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
10
|
.42**
|
|
Letter Agreement, dated as of October 24, 2007, by and
among Coffeyville Acquisition LLC, Goldman, Sachs &
Co. and Kelso & Company, L.P. (filed as
Exhibit 10.23 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2007 and
incorporated by reference herein).
|
|
10
|
.43**
|
|
Collective Bargaining Agreement, effective as of March 3,
2004, by and between Coffeyville Resources Refining &
Marketing, LLC and various unions of the Metal Trades Department
(filed as Exhibit 10.46 to the Companys Original
Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.44**
|
|
Collective Bargaining Agreement, effective as of March 3,
2004, by and between Coffeyville Resources Crude Transportation,
LLC and the Paper, Allied-Industrial, Chemical &
Energy Workers International Union (filed as Exhibit 10.47
to the Companys Original Registration Statement on
Form S-1,
File
No. 333-137588
and incorporated by reference herein).
|
|
10
|
.45**
|
|
Consulting Agreement dated May 2, 2008, by and between
General Wesley Clark and CVR Energy, Inc. (filed as
Exhibit 10.1 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended March 31, 2008 and
incorporated by reference herein).
|
|
21
|
.1**
|
|
List of Subsidiaries of CVR Energy, Inc. (filed as
Exhibit 21.1 to the Companys Annual Report on
Form 10-K
for the year ended December 31, 2007 and incorporated by
reference herein).
|
|
23
|
.1
|
|
Consent of KPMG LLP.
|
|
23
|
.2*
|
|
Consent of Fried, Frank, Harris, Shriver & Jacobson
LLP (included in Exhibit 5.1).
|
|
23
|
.3
|
|
Consent of Blue, Johnson & Associates.
|
|
|
|
*
|
|
To be filed by amendment.
|
|
**
|
|
Previously filed.
|
|
|
|
Confidential treatment has been granted for certain provisions
of this exhibit by the Securities and Exchange Commission.
|
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