10-Q
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
September 30, 2008
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number
001-33492
CVR ENERGY, INC.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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61-1512186
(I.R.S. Employer
Identification No.)
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2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of principal
executive offices)
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77479
(Zip Code)
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Registrants telephone number, including area code:
(281) 207-3200
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
.
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 o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined by
Rule 12b-2
of the Exchange
Act). Yes o No þ
.
There were 86,147,125 shares of the registrants
common stock outstanding at November 11, 2008.
CVR
ENERGY, INC. AND SUBSIDIARIES
INDEX TO
QUARTERLY REPORT ON
FORM 10-Q
For The Quarter Ended September 30, 2008
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Page No.
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Financial Statements (unaudited)
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2
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Condensed Consolidated Balance Sheets
September 30, 2008 and December 31, 2007
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2
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Condensed Consolidated Statements of
Operations Three and Nine Months Ended
September 30, 2008 and September 30, 2007
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3
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Condensed Consolidated Statements of Cash
Flows Nine Months Ended September 30, 2008 and
September 30, 2007
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4
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Notes to the Condensed Consolidated Financial
Statements September 30, 2008
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5
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Managements Discussion and Analysis of
Financial Condition and Results of Operations
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32
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Quantitative and Qualitative Disclosures About
Market Risk
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68
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Controls and Procedures
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68
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Legal Proceedings
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70
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Risk Factors
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70
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Exhibits
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70
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71
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Ex-10.1: Amendment to Amended and Restated Crude Oil Supply
Agreement dated as of September 26, 2008, between
Coffeyville Resources Refining & Marketing, LLC and J.
Aron & Company.
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Ex-10.2: Amended and Restated Settlement Deferral Letter, dated
as of October 11, 2008, between Coffeyville Resources, LLC
and J. Aron & Company.
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Ex-10.3: First Amendment to Amended and Restated
On-Site
Product Supply Agreement, dated October 31, 2008 between
Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc.
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Ex-10.4: Second Amendment to Amended and Restated Crude Oil
Supply Agreement dated as of October 31, 2008, between
Coffeyville Resources Refining & Marketing, LLC and J.
Aron & Company.
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Ex-31.1: Certification
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Ex-31.2: Certification
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Ex-32.1: Certification
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Ex-99.1: Risk Factors
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EX-10.1: AMENDMENT TO AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT |
EX-10.2: AMENDED AND RESTATED SETTLEMENT DEFERRAL LETTER |
EX-10.3: FIRST AMENDMENT TO AMENDED AND RESTATED ON-SITE PRODUCT SUPPLY AGREEMENT |
EX-10.4: SECOND AMENDMENT TO AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT |
EX-31.1: CERTIFICATION |
EX-31.2: CERTIFICATION |
EX-32.1: CERTIFICATION |
EX-99.1: RISK FACTORS |
PART I.
FINANCIAL INFORMATION
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ITEM 1.
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FINANCIAL
STATEMENTS
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CVR
ENERGY, INC. AND SUBSIDIARIES
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September 30,
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December 31,
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2008
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2007
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(Unaudited)
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(In thousands of dollars)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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59,862
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$
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30,509
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Accounts receivable, net of allowance for doubtful accounts of
$4,332 and $391, respectively
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130,086
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86,546
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Inventories
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258,911
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254,655
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Prepaid expenses and other current assets
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53,540
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14,186
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Insurance receivable
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19,278
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73,860
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Income tax receivable
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21,939
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31,367
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Deferred income taxes
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64,295
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79,047
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Total current assets
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607,911
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570,170
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Property, plant, and equipment, net of accumulated depreciation
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1,185,801
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1,192,174
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Intangible assets, net
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418
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473
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Goodwill
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83,775
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83,775
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Deferred financing costs, net
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6,041
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7,515
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Insurance receivable
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35,422
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11,400
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Other long-term assets
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6,113
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2,849
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Total assets
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$
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1,925,481
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$
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1,868,356
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LIABILITIES AND EQUITY
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Current liabilities:
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Current portion of long-term debt
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$
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4,837
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$
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4,874
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Note payable and capital lease obligations
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15,100
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11,640
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Payable to swap counterparty
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236,633
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262,415
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Accounts payable
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192,282
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182,225
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Personnel accruals
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19,704
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36,659
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Accrued taxes other than income taxes
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21,666
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14,732
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Deferred revenue
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15,359
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13,161
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Other current liabilities
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28,731
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33,820
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Total current liabilities
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534,312
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559,526
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Long-term liabilities:
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Long-term debt, less current portion
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480,705
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484,328
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Accrued environmental liabilities
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4,565
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4,844
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Deferred income taxes
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296,262
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286,986
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Other long-term liabilities
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1,209
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1,122
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Payable to swap counterparty
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27,903
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88,230
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Total long-term liabilities
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810,644
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865,510
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Commitments and contingencies
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Minority interest in subsidiaries
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10,600
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10,600
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Stockholders equity
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Common stock $0.01 par value per share;
350,000,000 shares authorized; 86,141,291 shares
issued and outstanding
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861
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861
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Additional
paid-in-capital
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442,700
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458,359
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Retained earnings (deficit)
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126,364
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(26,500
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)
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Total stockholders equity
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569,925
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432,720
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Total liabilities and stockholders equity
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$
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1,925,481
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$
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1,868,356
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See accompanying notes to the condensed consolidated financial
statements.
2
CVR
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2008
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2007
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2008
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2007
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As Restated()
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As Restated()
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(Unaudited)
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(In thousands except share amounts)
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Net sales
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$
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1,580,911
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$
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585,978
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$
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4,316,417
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$
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1,819,874
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Operating costs and expenses:
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Cost of product sold (exclusive of depreciation and amortization)
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1,440,355
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453,242
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3,764,026
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1,326,535
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Direct operating expenses (exclusive of depreciation and
amortization)
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56,575
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44,440
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179,467
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218,807
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Selling, general and administrative expenses (exclusive of
depreciation and amortization)
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(7,820
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)
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14,035
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20,439
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42,122
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Net costs associated with flood
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(817
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)
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32,192
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8,842
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34,331
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Depreciation and amortization
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20,609
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10,481
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61,324
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42,673
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Total operating costs and expenses
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1,508,902
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554,390
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4,034,098
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1,664,468
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Operating income
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72,009
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31,588
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282,319
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155,406
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Other income (expense):
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|
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Interest expense and other financing costs
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(9,334
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)
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(18,340
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)
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(30,092
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)
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(45,960
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)
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Interest income
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|
257
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|
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|
151
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1,560
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|
764
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|
Gain (loss) on derivatives, net
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76,706
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40,532
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(50,470
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)
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(251,912
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)
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Other income, net
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|
428
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|
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|
53
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858
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155
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Total other income (expense)
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68,057
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22,396
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(78,144
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)
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(296,953
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)
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Income (loss) before income taxes and minority interest in
subsidiaries
|
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140,066
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53,984
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204,175
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(141,547
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)
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Income tax expense (benefit)
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40,411
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42,731
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51,311
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(98,236
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)
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Minority interest in loss of subsidiaries
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(47
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)
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210
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|
|
|
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Net income (loss)
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$
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99,655
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$
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11,206
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$
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152,864
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$
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(43,101
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)
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Net income per share
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Basic
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$
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1.16
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$
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1.77
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Diluted
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$
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1.16
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$
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1.77
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Weighted average common shares outstanding
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Basic
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86,141,291
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86,141,291
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Diluted
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86,158,791
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86,158,791
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Pro Forma Information (note 12)
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Net income (loss) per share
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|
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|
|
|
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|
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Basic
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$
|
0.13
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|
|
|
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|
|
$
|
(0.50
|
)
|
Diluted
|
|
|
|
|
|
$
|
0.13
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|
|
|
|
|
|
$
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(0.50
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)
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Weighted average common shares outstanding
|
|
|
|
|
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|
|
|
|
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Basic
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|
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|
86,141,291
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|
|
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|
86,141,291
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Diluted
|
|
|
|
|
|
|
86,158,791
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
See accompanying notes to the condensed consolidated financial
statements.
3
CVR
ENERGY, INC. AND SUBSIDIARIES
|
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|
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|
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|
|
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Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands of dollars)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
152,864
|
|
|
$
|
(43,101
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
61,324
|
|
|
|
50,301
|
|
Provision for doubtful accounts
|
|
|
3,941
|
|
|
|
12
|
|
Amortization of deferred financing costs
|
|
|
1,487
|
|
|
|
1,947
|
|
Loss on disposition of fixed assets
|
|
|
1,550
|
|
|
|
1,246
|
|
Share-based compensation
|
|
|
(36,892
|
)
|
|
|
11,285
|
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
(210
|
)
|
Write-off of CVR Partners, LP initial public offering costs
|
|
|
2,539
|
|
|
|
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(47,481
|
)
|
|
|
4,160
|
|
Inventories
|
|
|
(11,373
|
)
|
|
|
(48,420
|
)
|
Prepaid expenses and other current assets
|
|
|
(31,799
|
)
|
|
|
4,186
|
|
Insurance receivable
|
|
|
1,060
|
|
|
|
(96,382
|
)
|
Insurance proceeds from flood
|
|
|
29,500
|
|
|
|
|
|
Other long-term assets
|
|
|
(3,553
|
)
|
|
|
1,589
|
|
Accounts payable
|
|
|
26,200
|
|
|
|
87,402
|
|
Accrued income taxes
|
|
|
9,428
|
|
|
|
(31,841
|
)
|
Deferred revenue
|
|
|
2,198
|
|
|
|
(2,064
|
)
|
Other current liabilities
|
|
|
6,123
|
|
|
|
32,309
|
|
Payable to swap counterparty
|
|
|
(86,109
|
)
|
|
|
230,928
|
|
Accrued environmental liabilities
|
|
|
(279
|
)
|
|
|
209
|
|
Other long-term liabilities
|
|
|
87
|
|
|
|
|
|
Deferred income taxes
|
|
|
24,028
|
|
|
|
(37,885
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
104,843
|
|
|
|
165,671
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(67,473
|
)
|
|
|
(239,695
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(67,473
|
)
|
|
|
(239,695
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Revolving debt payments
|
|
|
(453,200
|
)
|
|
|
(241,800
|
)
|
Revolving debt borrowings
|
|
|
453,200
|
|
|
|
261,800
|
|
Proceeds from issuance of term debt
|
|
|
|
|
|
|
50,000
|
|
Principal payments on long-term debt
|
|
|
(3,660
|
)
|
|
|
(3,871
|
)
|
Payment of capital lease obligation
|
|
|
(940
|
)
|
|
|
|
|
Payment of financing costs
|
|
|
|
|
|
|
(2,526
|
)
|
Deferred costs of CVR Partners, LP initial public offering
|
|
|
(2,429
|
)
|
|
|
|
|
Deferred costs of CVR Energy, Inc convertible debt offering
|
|
|
(988
|
)
|
|
|
|
|
Deferred costs of CVR Energy, Inc. initial public offering
|
|
|
|
|
|
|
(4,180
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(8,017
|
)
|
|
|
59,423
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
29,353
|
|
|
|
(14,601
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
30,509
|
|
|
|
41,919
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
59,862
|
|
|
$
|
27,318
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
|
Cash paid for income taxes, net of refunds (received)
|
|
$
|
17,854
|
|
|
$
|
(28,510
|
)
|
Cash paid for interest
|
|
|
36,718
|
|
|
|
37,363
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
Accrual of construction in progress additions
|
|
|
(16,143
|
)
|
|
|
(31,556
|
)
|
Assets acquired through capital lease
|
|
|
4,827
|
|
|
|
|
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
See accompanying notes to the condensed consolidated financial
statements.
4
CVR
ENERGY, INC. AND SUBSIDIARIES
September 30, 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 of high value
transportation fuels in the mid-continental United States and,
through a limited partnership, 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 other
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. The balance of the net proceeds
received were used for general corporate purposes.
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 common stock was 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
5
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
award vested 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 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 CVR
Partners, LP (the Partnership), a newly created limited
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 III LLC (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 by the
Partnership if it elects to pursue an initial public offering.
In addition, the Partnership and its subsidiaries are currently
guarantors under the credit facility of Coffeyville Resources,
LLC (CRLLC), a wholly-owned subsidiary of CVR. There will be no
distributions paid with respect to the IDRs for so long as the
Partnership or its subsidiaries are guarantors under the 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, 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 September 30, 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 assets into the Partnership in
exchange for its managing general partner interest and the IDRs.
In accordance with the Contribution, Conveyance, and Assumption
Agreement, by and between the Partnership and the partners,
dated as of October 24, 2007, if an initial private or
public offering of the Partnership is not consummated by
October 24, 2009, the managing general partner of the
Partnership can require the Company to purchase the managing GP
interest. This put right expires on the earlier of
(1) October 24, 2012 or (2) the closing of
6
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Partnerships initial private or public offering. If
the Partnerships initial private or public offering is not
consummated by October 24, 2012, the Company has the right
to require the managing general partner to sell the managing GP
interest to the Company. This call right expires on the closing
of the Partnerships initial private or public 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 GP
interest at the time of the purchase determined by an
independent investment banking firm selected by the Company and
the managing general partner.
On February 28, 2008, the Partnership filed a registration
statement with the Securities and Exchange Commission (SEC) to
effect an initial public offering of its common units
representing limited partner interests. 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 due to then-existing
market conditions for master limited partnerships. The
Partnership, subsequently, withdrew the registration statement.
As of September 30, 2008, the Partnership had distributed
$50.0 million to CVR.
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.
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 September 30, 2008
and December 31, 2007, the results of operations for the
three and nine months ended September 30, 2008 and 2007,
and the cash flows for the nine months ended September 30,
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. GAAP 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,
$4.2 million of deferred offering costs for the nine months
ended September 30, 2007 were previously presented in
operating activities in the interim financial statements. Such
amounts have now been reflected as financing activities for the
nine months ended September 30, 2007 in the accompanying
Consolidated Statements of Cash Flows. The impact on the prior
financial statements of this revision is not considered material.
|
|
(2)
|
Restatement
of Financial Statements
|
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.
7
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The restatement principally related to errors in the calculation
of the cost of crude oil purchased by the Company and associated
financial transactions. Accordingly, the Company restated the
previously issued financial statements for these periods.
Restated financial information, as well as a discussion of the
errors and the adjustments made as a result of the restatement,
are contained in the Companys amended Annual Report on
Form 10K/A for the year ended December 31, 2007. The
Company did not amend the Companys previously filed
Quarterly Report on
Form 10-Q
for the period ended September 30, 2007.
As a result of the restatement, for the three months ended
September 30, 2007, net income decreased by
$2.2 million, from $13.4 million to
$11.2 million. In addition, for the nine months ended
September 30, 2007, net loss increased by $2.2 million
from $40.9 million to $43.1 million. These changes
resulted from an increase in cost of product sold (exclusive of
depreciation and amortization) of $7.1 million for both
periods, with an associated increase in income tax benefit of
$4.9 million for both periods.
Due to the restatement, accounts payable for the quarter ended
September 30, 2007 increased by $7.1 million. Income
tax receivable increased by $3.0 million, current deferred
income tax asset increased by $4.2 million, and long term
deferred income tax liability increased by $2.3 million.
The effect of the above adjustments on the condensed
consolidated financial statements is set forth in the tables
below. The restatement had no effect on net cash flow 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
September 30, 2007.
Notes 11, 12, 16, and 17 have been restated to reflect the
adjustments described above.
8
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Condensed
Consolidated Balance Sheet Data
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
|
Previously
|
|
|
Restatement
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
27,318
|
|
|
$
|
|
|
|
$
|
27,318
|
|
Accounts receivable, net of allowance for doubtful accounts of
$387
|
|
|
65,417
|
|
|
|
|
|
|
|
65,417
|
|
Inventories
|
|
|
209,853
|
|
|
|
|
|
|
|
209,853
|
|
Prepaid expenses and other current assets
|
|
|
28,190
|
|
|
|
|
|
|
|
28,190
|
|
Insurance receivable
|
|
|
84,982
|
|
|
|
|
|
|
|
84,982
|
|
Income tax receivable
|
|
|
60,937
|
|
|
|
3,003
|
|
|
|
63,940
|
|
Deferred income taxes
|
|
|
99,560
|
|
|
|
4,225
|
|
|
|
103,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
576,257
|
|
|
|
7,228
|
|
|
|
583,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment, net of accumulated depreciation
|
|
|
1,164,047
|
|
|
|
|
|
|
|
1,164,047
|
|
Intangible assets, net
|
|
|
497
|
|
|
|
|
|
|
|
497
|
|
Goodwill
|
|
|
83,775
|
|
|
|
|
|
|
|
83,775
|
|
Deferred financing costs, net
|
|
|
8,012
|
|
|
|
|
|
|
|
8,012
|
|
Insurance receivable
|
|
|
11,400
|
|
|
|
|
|
|
|
11,400
|
|
Other long-term assets
|
|
|
4,580
|
|
|
|
|
|
|
|
4,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,848,568
|
|
|
|
7,228
|
|
|
|
1,855,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
57,682
|
|
|
$
|
|
|
|
$
|
57,682
|
|
Revolving debt
|
|
|
20,000
|
|
|
|
|
|
|
|
20,000
|
|
Note payable and capital lease obligations
|
|
|
5,947
|
|
|
|
|
|
|
|
5,947
|
|
Payable to swap counterparty
|
|
|
241,427
|
|
|
|
|
|
|
|
241,427
|
|
Accounts payable
|
|
|
189,714
|
|
|
|
7,072
|
|
|
|
196,786
|
|
Personnel accruals
|
|
|
31,535
|
|
|
|
|
|
|
|
31,535
|
|
Accrued taxes other than income taxes
|
|
|
9,648
|
|
|
|
|
|
|
|
9,648
|
|
Deferred revenue
|
|
|
6,748
|
|
|
|
|
|
|
|
6,748
|
|
Other current liabilities
|
|
|
40,551
|
|
|
|
|
|
|
|
40,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
603,252
|
|
|
|
7,072
|
|
|
|
610,324
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
763,447
|
|
|
|
|
|
|
|
763,447
|
|
Accrued environmental liabilities
|
|
|
5,604
|
|
|
|
|
|
|
|
5,604
|
|
Deferred income taxes
|
|
|
328,785
|
|
|
|
2,349
|
|
|
|
331,134
|
|
Payable to swap counterparty
|
|
|
99,202
|
|
|
|
|
|
|
|
99,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
1,197,038
|
|
|
|
2,349
|
|
|
|
1,199,387
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in subsidiaries
|
|
|
5,169
|
|
|
|
|
|
|
|
5,169
|
|
Management voting common units subject to redemption,
201,063 units issued and outstanding in 2007
|
|
|
8,656
|
|
|
|
|
|
|
|
8,656
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Voting common units, 22,614,937 units issued and
outstanding in 2007
|
|
|
29,958
|
|
|
|
(2,193
|
)
|
|
|
27,765
|
|
Management nonvoting override units, 2,976,353 units issued
and outstanding in 2007
|
|
|
4,495
|
|
|
|
|
|
|
|
4,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
34,453
|
|
|
|
(2,193
|
)
|
|
|
32,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,848,568
|
|
|
$
|
7,228
|
|
|
$
|
1,855,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Condensed
Consolidated Statement of Operations Data
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30, 2007
|
|
|
September 30, 2007
|
|
|
|
Previously
|
|
|
Restatement
|
|
|
|
|
|
Previously
|
|
|
Restatement
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
Net Sales
|
|
$
|
585,978
|
|
|
$
|
|
|
|
$
|
585,978
|
|
|
$
|
1,819,874
|
|
|
$
|
|
|
|
$
|
1,819,874
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
446,170
|
|
|
|
7,072
|
|
|
|
453,242
|
|
|
|
1,319,463
|
|
|
|
7,072
|
|
|
|
1,326,535
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
44,440
|
|
|
|
|
|
|
|
44,440
|
|
|
|
218,807
|
|
|
|
|
|
|
|
218,807
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
14,035
|
|
|
|
|
|
|
|
14,035
|
|
|
|
42,122
|
|
|
|
|
|
|
|
42,122
|
|
Net costs associated with flood
|
|
|
32,192
|
|
|
|
|
|
|
|
32,192
|
|
|
|
34,331
|
|
|
|
|
|
|
|
34,331
|
|
Depreciation and amortization
|
|
|
10,481
|
|
|
|
|
|
|
|
10,481
|
|
|
|
42,673
|
|
|
|
|
|
|
|
42,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
547,318
|
|
|
|
7,072
|
|
|
|
554,390
|
|
|
|
1,657,396
|
|
|
|
7,072
|
|
|
|
1,664,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
38,660
|
|
|
|
(7,072
|
)
|
|
|
31,588
|
|
|
|
162,478
|
|
|
|
(7,072
|
)
|
|
|
155,406
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(18,340
|
)
|
|
|
|
|
|
|
(18,340
|
)
|
|
|
(45,960
|
)
|
|
|
|
|
|
|
(45,960
|
)
|
Interest income
|
|
|
151
|
|
|
|
|
|
|
|
151
|
|
|
|
764
|
|
|
|
|
|
|
|
764
|
|
Gain (loss) on derivatives, net
|
|
|
40,532
|
|
|
|
|
|
|
|
40,532
|
|
|
|
(251,912
|
)
|
|
|
|
|
|
|
(251,912
|
)
|
Other income, net
|
|
|
53
|
|
|
|
|
|
|
|
53
|
|
|
|
155
|
|
|
|
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
22,396
|
|
|
|
|
|
|
|
22,396
|
|
|
|
(296,953
|
)
|
|
|
|
|
|
|
(296,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
|
61,056
|
|
|
|
(7,072
|
)
|
|
|
53,984
|
|
|
|
(134,475
|
)
|
|
|
(7,072
|
)
|
|
|
(141,547
|
)
|
Income tax expense (benefit)
|
|
|
47,610
|
|
|
|
(4,879
|
)
|
|
|
42,731
|
|
|
|
(93,357
|
)
|
|
|
(4,879
|
)
|
|
|
(98,236
|
)
|
Minority interest in loss of subsidiaries
|
|
|
(47
|
)
|
|
|
|
|
|
|
(47
|
)
|
|
|
210
|
|
|
|
|
|
|
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
13,399
|
|
|
$
|
(2,193
|
)
|
|
$
|
11,206
|
|
|
$
|
(40,908
|
)
|
|
$
|
(2,193
|
)
|
|
$
|
(43,101
|
)
|
Unaudited Pro Form Information (Note 12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.16
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.47
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.50
|
)
|
Diluted
|
|
$
|
0.16
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.47
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.50
|
)
|
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
|
|
|
|
(3)
|
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
10
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
September 30, 2008, the only financial assets and financial
liabilities that are within the scope of SFAS 157 and
measured at fair value on a recurring basis are the
Companys derivative instruments. See Note 15,
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 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.
|
|
(4)
|
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 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 addition, in connection with the transfer of the
managing general partner of the Partnership to CALLC III in
October 2007, 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 through the performance commitment period, or
in CVRs case, through the vesting period. At
September 30, 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 value per unit
reflects a ratio of override units to shares of common stock in
correlation with the percentage for
11
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
which the override units can share in conjunction with the
benchmark value. The estimated fair value of the override units
of CALLC III has been determined using a 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 table provides key information for the share-based
compensation plans related to the override units of CALLC, CALLC
II, and CALLC III. Compensation expense amounts are disclosed in
thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Compensation Expense Increase
|
|
|
*Compensation Expense Increase
|
|
|
|
Benchmark
|
|
|
|
|
|
|
|
(Decrease) for the
|
|
|
(Decrease) for the Nine Months
|
|
|
|
Value
|
|
|
Awards
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Ended September 30,
|
|
Award Type
|
|
(per Unit)
|
|
|
Issued
|
|
|
Grant Date
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Override Operating Units(a)
|
|
$
|
11.31
|
|
|
|
919,630
|
|
|
June 2005
|
|
$
|
(748
|
)
|
|
$
|
178
|
|
|
$
|
(5,272
|
)
|
|
|
743
|
|
Override Operating Units(b)
|
|
$
|
34.72
|
|
|
|
72,492
|
|
|
December 2006
|
|
|
(199
|
)
|
|
|
41
|
|
|
|
(454
|
)
|
|
|
236
|
|
Override Value Units(c)
|
|
$
|
11.31
|
|
|
|
1,839,265
|
|
|
June 2005
|
|
|
(6,978
|
)
|
|
|
169
|
|
|
|
(10,176
|
)
|
|
|
508
|
|
Override Value Units(d)
|
|
$
|
34.72
|
|
|
|
144,966
|
|
|
December 2006
|
|
|
(481
|
)
|
|
|
52
|
|
|
|
(555
|
)
|
|
|
155
|
|
Override Units(e)
|
|
$
|
10.00
|
|
|
|
138,281
|
|
|
October 2007
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
Override Units(f)
|
|
$
|
10.00
|
|
|
|
642,219
|
|
|
February 2008
|
|
|
510
|
|
|
|
|
|
|
|
511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(7,896
|
)
|
|
$
|
440
|
|
|
$
|
(15,947
|
)
|
|
$
|
1,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
As CVRs common stock price increases or decreases
compensation expense increases or is reversed in correlation to
such increases or decreases in the stock price subject to
certain limitations. |
Valuation
Assumptions
|
|
|
(a) |
|
In accordance with SFAS 123(R), using the Monte Carlo
method of valuation, the estimated fair value of the override
operating units on June 24, 2005 was $3,605,000.
Significant assumptions used in the valuation were as follows: |
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture schedule in (b) below
|
|
Based on forfeiture schedule in (b) below
|
Grant date fair value
|
|
$5.16 per share
|
|
N/A
|
September 30, 2008 CVR closing stock price
|
|
N/A
|
|
$8.52
|
September 30, 2008 estimated fair value
|
|
N/A
|
|
$17.54 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
N/A
|
12
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(b) |
|
In accordance with SFAS 123(R), using a combination of a
binomial model and a probability-weighted expected return method
which utilized CVRs cash flow projections, the estimated
fair value of the override operating units on December 28,
2006 was $473,000. Significant assumptions used in the valuation
were as follows: |
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture schedule below
|
|
Based on forfeiture schedule below
|
Grant date fair value
|
|
$8.15 per share
|
|
N/A
|
September 30, 2008 CVR closing stock price
|
|
N/A
|
|
$8.52
|
September 30, 2008 estimated fair value
|
|
N/A
|
|
$0 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
N/A
|
On the tenth anniversary of the issuance of override operating
units, such units convert into an equivalent number of override
value units. 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 as follows:
|
|
|
|
|
Minimum
|
|
Forfeiture
|
|
Period Held
|
|
Rate
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
|
|
|
(c) |
|
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. Significant
assumptions used in the valuation were as follows: |
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$2.91 per share
|
|
N/A
|
September 30, 2008 CVR closing stock price
|
|
N/A
|
|
$8.52
|
September 30, 2008 estimated fair value
|
|
N/A
|
|
$7.06 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
N/A
|
13
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(d) |
|
In accordance with SFAS 123(R), using a combination of a
binomial model and a probability-weighted expected return method
which utilized CVRs cash flow projections, the estimated
fair value of the override value units on December 28, 2006
was $945,000. Significant assumptions used in the valuation were
as follows: |
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$8.15 per share
|
|
N/A
|
September 30, 2008 CVR closing stock price
|
|
N/A
|
|
$8.52
|
September 30, 2008 estimated fair value
|
|
N/A
|
|
$0 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 as follows:
|
|
|
|
|
|
|
Subject to
|
|
Minimum
|
|
Forfeiture
|
|
Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
|
|
|
(e) |
|
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 which includes expected future earnings and
the anticipated timing of IDRs, the estimated grant date fair
value of the override units was approximately $3,000. As of
September 30, 2008 these units were fully vested.
Significant assumptions used in the valuation were as follows: |
|
|
|
Estimated forfeiture rate
|
|
None
|
September 30, 2008 estimated fair value
|
|
$0.007 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
36.2%
|
|
|
|
(f) |
|
In accordance with SFAS 123(R), Share-Based
Compensation, using a probability-weighted expected return
method which utilized CALLC IIIs cash flows projections
which includes expected future earnings and the anticipated
timing of IDRs, the estimated grant date fair value of the
override units was approximately $3,000. Of the
642,219 units issued, 109,720 were immediately vested upon
issuance and the remaining units are subject to a forfeiture
schedule. Significant assumptions used in the valuation were as
follows: |
|
|
|
Estimated forfeiture rate
|
|
None
|
Derived Service Period
|
|
Based on forfeiture schedule
|
September 30, 2008 estimated fair value
|
|
$3.77 per share
|
Marketability and minority interest discount
|
|
20% discount
|
Volatility
|
|
45.0%
|
14
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At September 30, 2008, assuming no change in the estimated
fair value at September 30, 2008, there was approximately
$8.0 million of unrecognized compensation expense related
to non-voting override units. This is expected to be recognized
over a remaining period of approximately three years as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
|
|
Operating
|
|
|
Value
|
|
|
|
Units
|
|
|
Units
|
|
|
Three months ending December 31, 2008
|
|
$
|
457
|
|
|
$
|
545
|
|
Year ending December 31, 2009
|
|
|
1,287
|
|
|
|
2,164
|
|
Year ending December 31, 2010
|
|
|
387
|
|
|
|
2,164
|
|
Year ending December 31, 2011
|
|
|
|
|
|
|
1,032
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,131
|
|
|
$
|
5,905
|
|
|
|
|
|
|
|
|
|
|
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
September 30, 2008, the issued Profits Interest (combined
phantom points 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 September 30, 2008 CVR closing
common stock price to determine the Companys equity value,
the service phantom interest and performance phantom interest
were valued at $17.54 and $7.06 per point, respectively. CVR has
recorded approximately $7,984,000 and $29,217,000 in personnel
accruals as of September 30, 2008 and December 31,
2007, respectively. Compensation expense for the three and nine
month periods ending September 30, 2008 related to the
Phantom Unit Appreciation Plan was reversed by $(17,977,000) and
$(21,233,000), respectively. Compensation expense for the three
and nine month periods ending September 30, 2007 was
$4,062,000 and $9,641,000, respectively.
At September 30, 2008, assuming no change in the estimated
fair value at September 30, 2008, there was approximately
$2.9 million of unrecognized compensation expense related
to the Phantom Unit Appreciation Plan. This is expected to be
recognized over a remaining period of approximately three years.
Long
Term Incentive Plan
CVR has a Long Term Incentive Plan which permits the grant of
options, stock appreciation rights, or SARS, non-vested shares,
non-vested share units, dividend equivalent rights, share awards
and performance awards.
During the quarter there were no forfeitures or vesting of stock
options or non-vested shares. On September 24, 2008,
options to purchase 9,100 shares of common stock at an
exercise price of $11.01 per share were granted to an outside
director upon his election to the Companys board of
directors.
As of September 30, 2008, there was approximately
$0.4 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
September 30, 2008 and 2007 related to the non-vested
common stock and common stock options was $102,000 and $0,
respectively. Compensation expense recorded for the nine month
periods ending September 30, 2008 and 2007 related to the
non-vested common stock and common stock options was $288,000
and $0, respectively.
15
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Finished goods
|
|
$
|
110,106
|
|
|
$
|
109,394
|
|
Raw materials and catalysts
|
|
|
94,164
|
|
|
|
92,104
|
|
In-process inventories
|
|
|
27,304
|
|
|
|
29,817
|
|
Parts and supplies
|
|
|
27,337
|
|
|
|
23,340
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
258,911
|
|
|
$
|
254,655
|
|
|
|
|
|
|
|
|
|
|
|
|
(6)
|
Property,
Plant, and Equipment
|
A summary of costs for property, plant, and equipment is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Land and improvements
|
|
$
|
17,672
|
|
|
$
|
13,058
|
|
Buildings
|
|
|
21,955
|
|
|
|
17,541
|
|
Machinery and equipment
|
|
|
1,288,553
|
|
|
|
1,108,858
|
|
Automotive equipment
|
|
|
6,448
|
|
|
|
5,171
|
|
Furniture and fixtures
|
|
|
7,593
|
|
|
|
6,304
|
|
Leasehold improvements
|
|
|
1,169
|
|
|
|
929
|
|
Construction in progress
|
|
|
44,527
|
|
|
|
182,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,387,917
|
|
|
|
1,333,907
|
|
Accumulated depreciation
|
|
|
202,116
|
|
|
|
141,733
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,185,801
|
|
|
$
|
1,192,174
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest recognized as a reduction in interest
expense for the three month periods ended September 30,
2008 and September 30, 2007 totaled approximately $244,000
and $2,877,000, respectively. Capitalized interest for the nine
month periods ended September 30, 2008 and
September 30, 2007 totaled approximately $1,565,000 and
$9,285,000, respectively. Land and buildings that are under a
capital lease obligation approximate $4,827,000.
|
|
(7)
|
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 nitrogen
fertilizer plant recently completed a major scheduled turnaround
in October 2008. The refinery started a major scheduled
turnaround in February 2007 with completion in April 2007. Costs
of $138,000 associated with the 2008 fertilizer plant turnaround
were included in direct operating expenses (exclusive of
depreciation and amortization) for the three and
16
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
nine months ended September 30, 2008. Costs of $0 and
$76,754,000 associated with the 2007 refinery turnaround were
included in direct operating expenses (exclusive of depreciation
and amortization) for the three and nine months ending
September 30, 2007, respectively.
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 $605,000 and $595,000 for the three months ended
September 30, 2008 and September 30, 2007,
respectively. For the nine months ended September 30, 2008
and 2007 cost of product sold excludes depreciation and
amortization of $1,816,000 and $1,791,000, 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 $19,486,000 and $9,582,000 for
the three months ended September 30, 2008 and 2007,
respectively. For the nine months ended September 30, 2008
and 2007, direct operating expenses excludes depreciation and
amortization of $58,296,000 and $40,202,000, respectively.
Direct operating expenses also exclude depreciation of
$7,627,000 for both the three and nine months ended
September 30, 2007 that is included in Net costs
associated with the flood on the condensed consolidated
statement of operations as a result of assets being idled 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 $518,000 and $304,000 for the three months ended
September 30, 2008 and September 30, 2007,
respectively. For the nine months ended September 30, 2008
and 2007, selling, general and administrative expenses excludes
depreciation and amortization of $1,212,000 and $680,000,
respectively.
|
|
(9)
|
Note
Payable and Capital Lease Obligations
|
The Company entered into an insurance premium finance agreement
with Cananwill, Inc. in July 2008 and July 2007 to finance the
purchase of its property, liability, cargo and terrorism
policies. The original balances of these notes were
$10.0 million and $7.6 million for 2008 and 2007,
respectively. Both notes were to be repaid in equal installments
with the final payment due for the 2008 note in June 2009. The
balance due for the July 2007 note was paid in full in April
2008. As of September 30, 2008 and December 31, 2007
the Company owed $10.0 million and $3.4 million
related to these notes.
The Company entered into two capital leases in 2007 to lease
platinum required in the manufacturing of new catalyst. The
recorded lease obligations fluctuate with the platinum market
price. The leases 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 September 30, 2008 and December 31, 2007 the
lease obligations were recorded at approximately
$1.1 million and $8.2 million on the Consolidated
Balance Sheets, respectively.
The Company also entered into a capital lease for real property
used for corporate purposes on May 29, 2008. The lease has
an initial lease term of one year with an option to renew for
three additional one-year periods. The Company has the option to
purchase the property during the initial lease term or during
the renewal periods if the lease is renewed. In connection with
the capital lease the Company recorded a capital asset and
capital lease obligation of $4.8 million. The capital lease
obligation was $4.0 million as of September 30, 2008.
|
|
(10)
|
Flood,
Crude Oil Discharge 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
17
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, up to $300 million per occurrence, subject to
deductibles and other limitations. The deductible associated
with the property damage was $2.5 million.
Additionally, crude oil was discharged from the Companys
refinery on July 1, 2007 due to the short amount of time to
shut down and save the refinery in preparation of the flood that
occurred on June 30, 2007. The Company maintained insurance
policies related to environmental cleanup costs and potential
liability to third parties for bodily injury or property damage.
The policies were subject to a $1.0 million self-insured
retention.
The Company has submitted voluminous claims information to, and
continues to respond to information requests from, the insurers
with respect to costs and damages related to the 2007 flood and
crude oil discharge. See Note 13, Commitments and
Contingent Liabilities for additional information
regarding environmental and other contingencies relating to the
crude oil discharge that occurred on July 1, 2007.
As of September 30, 2008, the Company has recorded total
gross costs associated with the repair of and other matters
relating to the damage to the Companys facilities and with
third party and property damage claims incurred due to the crude
oil discharge of approximately $154.6 million. Total
anticipated insurance recoveries of approximately
$104.2 million have been recorded as of September 30,
2008 (of which $49.5 million had already been received as
of September 30, 2008 by the Company from insurance
carriers). At September 30, 2008, total accounts receivable
from insurance were $54.7 million. The receivable balance
is segregated between current and long-term in the
Companys Consolidated Balance Sheet in relation to the
nature and classification of the items to be settled. As of
September 30, 2008, $35.4 million of the amounts
receivable from insurers were not anticipated to be collected in
the next twelve months, and therefore has been classified as a
non-current asset.
Management believes the recovery of the receivable from the
insurance carriers is probable. While management believes that
the Companys property insurance should cover substantially
all of the estimated total costs associated with the physical
damage to the property, the Companys insurance carriers
have cited potential coverage limitations and defenses, which
while unlikely to preclude recovery, could do so and are
anticipated to delay collection for more than twelve months.
The Companys property insurers have raised a question as
to whether the Companys facilities are principally located
in Zone A, which was, at the time of the flood,
subject to a $10 million insurance limit for flood, or
Zone B, which was, at the time of the flood,
subject to a $300 million insurance limit for flood. The
Company has reached an agreement with certain of its property
insurers representing approximately 32.5% of its total property
coverage for the flood that the facilities are principally
located in Zone B and therefore subject to the
$300 million limit for the flood. The remaining property
insurers have not, at this time, agreed to this position. In
addition, the Companys excess environmental liability
insurance carrier has asserted that the pollution liability
claims are for cleanup, which is not covered under
its policy, rather than for property damage, which
is covered to the limits of the policy. While the Company will
vigorously contest the excess carriers position, the
Company contends that if that position were upheld, the
Companys umbrella Comprehensive General Liability policies
would continue to provide coverage for these claims. Each
insurer, however, has reserved its rights under various policy
exclusions and limitations and has cited potential coverage
defenses. On July 10, 2008, the Company filed two lawsuits
against certain of its insurance carriers. One lawsuit was filed
against the nonsettling property damage insurance carriers, and
the second lawsuit was filed against carriers under the
environmental insurance policies. The property insurance lawsuit
involved the Zone A/Zone B issue, and the pollution insurance
lawsuit involved the cleanup/property damage issue described
above. The Company intends to pursue the litigation vigorously.
The Companys primary pollution liability carrier has
settled with the Company by paying the full $25.0 million
policy limit and has been dismissed from the pollution insurance
lawsuit. The $25.0 million payment from the Companys
environmental insurer is included within the $49.5 million
of insurance proceeds at September 30, 2008. Considering
the effect of the lawsuits, the Company continues to believe its
remaining receivable as of September 30, 2008 of
$54.7 million is probable of recovery.
18
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 net pretax costs in total since the
occurrence of the flood of approximately $50.4 million
associated with both the flood and related crude oil discharge
as discussed in Note 13, Commitments and Contingent
Liabilities. This amount is net of anticipated insurance
recoveries of $104.2 million.
Below is a summary of the gross cost associated with the flood
and crude oil discharge and reconciliation of the insurance
receivable (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
|
|
|
For the Three
|
|
|
For the Nine
|
|
|
For the Nine
|
|
|
|
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
Total
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Total gross costs incurred
|
|
$
|
154.6
|
|
|
$
|
1.0
|
|
|
$
|
128.6
|
|
|
$
|
7.8
|
|
|
$
|
130.7
|
|
Total insurance receivable
|
|
|
(104.2
|
)
|
|
|
(1.8
|
)
|
|
|
(96.4
|
)
|
|
|
1.1
|
|
|
|
(96.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with the flood
|
|
$
|
50.4
|
|
|
$
|
(0.8
|
)
|
|
$
|
32.2
|
|
|
$
|
8.9
|
|
|
$
|
34.3
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
Reconciliation
|
|
|
Total insurance receivable
|
|
$
|
104.2
|
|
Less insurance proceeds received through September 30, 2008
|
|
|
(49.5
|
)
|
|
|
|
|
|
Insurance receivable
|
|
$
|
54.7
|
|
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.
In 2007, the Company 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. In the third quarter of 2008, the Company received
$13.0 million under its property insurance policy and
$15.0 million was received from one environmental insurance
carrier in settlement of their expected total obligation. In
October 2008, the Company through certain wholly-owned
subsidiaries submitted an advance payment proof of loss to
certain of its insurers for unallocated property damage. The
Company expects to receive an advance payment related thereto in
the amount of approximately $10.1 million. As of
November 6, 2008, the Company has received
$9.8 million of the $10.1 million total increasing the
total insurance recoveries received from $49.5 million at
September 30, 2008 to $59.3 million as of
November 6, 2008. The Company continues to reserve all
rights under all relevant policies. See Note 13,
Commitments and Contingent Liabilities for
additional information regarding environmental and other
contingencies relating to the crude oil discharge that occurred
on July 1, 2007.
19
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 September 30, 2008.
As of September 30, 2008, the Company did not have an
accrual for any amounts for interest or penalties related to
uncertain tax positions. The Companys accounting policy
with respect to interest and penalties related to tax
uncertainties is to classify these amounts as income taxes.
CVR and its subsidiaries file U.S. federal and various
state income and franchise tax returns. The Companys
U.S. federal income tax return for its 2005 tax year is
currently under examination. An examination of the
Companys 2004 through 2007 Texas franchise recently
commenced. The Company has not been subject to any other
U.S. federal or state income or franchise tax examinations
by taxing authorities with respect to other income and franchise
tax returns. The Companys U.S. federal and state tax
years subject to examination as of October 31, 2008 are
2005 to 2007.
The Companys effective tax rate for the nine months ended
September 30, 2008 and 2007 was 25.1% and 69.3%,
respectively, as compared to the Companys combined federal
and state expected statutory tax rate of 39.9%. The effective
tax rate is lower than the expected statutory tax rate for the
nine months ended September 30, 2008 due primarily 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). The annualized effective tax rate in
2008 is lower than 2007 due to the correlation between the
amount of credits projected to be generated in each year in
relative comparison with the projected pre-tax loss level in
2007 and pre-tax income level in 2008.
|
|
(12)
|
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 the Company
and Basis of Presentation.
2008
Earnings Per Share
Earnings per share for the three and nine months ended
September 30, 2008 is calculated as noted below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30, 2008
|
|
|
September 30, 2008
|
|
|
|
Earnings
|
|
|
Shares
|
|
|
Per Share
|
|
|
Earnings
|
|
|
Shares
|
|
|
Per Share
|
|
|
Basic earnings per share
|
|
$
|
99,655,000
|
|
|
|
86,141,291
|
|
|
$
|
1.16
|
|
|
$
|
152,864,000
|
|
|
|
86,141,291
|
|
|
$
|
1.77
|
|
Diluted earnings per share
|
|
$
|
99,655,000
|
|
|
|
86,158,791
|
|
|
$
|
1.16
|
|
|
$
|
152,864,000
|
|
|
|
86,158,791
|
|
|
$
|
1.77
|
|
Outstanding stock options totaling 32,350 common shares were
excluded from the diluted earnings per share calculation for the
three and nine months ended September 30, 2008 as they were
antidilutive.
20
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2007
Earnings (Loss) Per Share
The computation of basic and diluted loss per share for the
three and nine months ended September 30, 2007 is
calculated on a pro forma basis assuming the capital structure
in place after the completion of the initial public offering was
in place for the entire period.
Pro forma earnings (loss) per share for the three and nine
months ended September 30, 2007 is calculated as noted
below. For the nine months ended September 30, 2007, 17,500
non-vested shares of common stock 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:
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2007
|
|
|
2007
|
|
|
|
As Restated()
|
|
|
As Restated()
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
Net income (loss)
|
|
$
|
11,206,000
|
|
|
$
|
(43,101,000
|
)
|
Pro forma weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Original CVR shares of common stock
|
|
|
100
|
|
|
|
100
|
|
Effect of 628,667.20 to 1 stock split
|
|
|
62,866,620
|
|
|
|
62,866,620
|
|
Issuance of shares of common stock to management in exchange for
subsidiary shares
|
|
|
247,471
|
|
|
|
247,471
|
|
Issuance of shares of common stock to employees
|
|
|
27,100
|
|
|
|
27,100
|
|
Issuance of shares of common stock 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 non-vested shares of
common stock to board of directors
|
|
|
17,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
|
|
|
Pro forma basic earnings (loss) per share
|
|
$
|
0.13
|
|
|
$
|
(0.50
|
)
|
Pro forma dilutive earnings (loss) per share
|
|
$
|
0.13
|
|
|
$
|
(0.50
|
)
|
|
|
|
|
|
See Note 2 to condensed consolidated financial statements. |
|
|
(13)
|
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
|
|
|
Three months ending December 31, 2008
|
|
$
|
943
|
|
|
$
|
7,455
|
|
Year ending December 31, 2009
|
|
|
3,293
|
|
|
|
28,685
|
|
Year ending December 31, 2010
|
|
|
2,169
|
|
|
|
37,526
|
|
Year ending December 31, 2011
|
|
|
950
|
|
|
|
56,593
|
|
Year ending December 31, 2012
|
|
|
198
|
|
|
|
53,908
|
|
Thereafter
|
|
|
11
|
|
|
|
411,263
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,564
|
|
|
$
|
595,430
|
|
|
|
|
|
|
|
|
|
|
21
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company leases various equipment, including rail cars, and
real properties under long-term operating leases, expiring at
various dates. In the normal course of business, the Company
also has long-term commitments to purchase services such as
natural gas, electricity, water and transportation services. For
the three months ended September 30, 2008 and 2007, lease
expense totaled $1,102,000 and $850,000, respectively. For the
nine months ended September 30, 2008 and 2007, lease
expense totaled $3,176,000 and $2,812,000, 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 outcome and costs are probable and
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. In connection with that
discharge, the Company received in May 2008 notices of claims
from sixteen private claimants under the Oil Pollution Act in
aggregate amount of approximately $4.4 million. In August
2008, those claimants filed suit against the Company in the
United States District Court for the District of Kansas in
Wichita. The Company believes that the resolution of these
claims will not have a material adverse effect on the
consolidated financial statements.
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 substantially completed remediating the damage caused by
the crude oil discharge in July 2008 and expects any remaining
minor remedial actions to be completed by December 31,
2008. The Company is currently preparing its final report to the
EPA to satisfy the final requirement of the Consent Order.
As of September 30, 2008, the total gross costs recorded
associated with remediation and third party property damage as a
result of the crude oil discharge approximated
$52.9 million. The Company has not estimated or accrued for
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 as management does
not believe any such fines, penalties or lawsuits would be
material nor can be estimated.
While the remediation efforts were substantially completed in
July 2008, 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,
resolution of class action lawsuits, and other claims brought by
regulatory authorities. Our excess environmental liability
insurance carrier has asserted that our pollution liability
claims are for cleanup, which is not covered by such
policy, rather than for property damage, which is
covered to the limits of the policy. While we will vigorously
contest the excess carriers position, we contend that if
that position were upheld, our umbrella Comprehensive General
Liability policies would continue to provide coverage for these
claims. Each insurer, however, has reserved its rights under
various policy exclusions and limitations and has cited
potential coverage defenses. Although the Company believes that
substantial sums under the environmental and liability insurance
22
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
policies will be recovered, the Company can not be certain 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 primary
environmental liability insurance policy in 2007 and received an
additional $15.0 million in September 2008 from that
carrier, which two payments together constituted full payment to
the Company of the primary pollution liability policy limit.
On July 10, 2008, the Company filed two lawsuits in the
United States District Court for the District of Kansas against
certain of the Companys insurance carriers with regard to
the Companys insurance coverage for the flood and crude
oil discharge. One of the lawsuits was filed against the
insurance carriers under the environmental policies.
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 Administrative Orders 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 September 30, 2008 and
December 31, 2007, environmental accruals of $7,079,000 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 $2,514,000 and
$2,802,000, respectively, included in other current liabilities.
The Companys accruals were determined based on an estimate
of payment costs through 2031, which scope of remediation was
arranged with the EPA and are discounted at the appropriate risk
free rates at September 30, 2008 and December 31,
2007, respectively. The accruals include estimated closure and
post-closure costs of $1,524,000
23
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and $1,549,000 for two landfills at September 30, 2008 and
December 31, 2007, respectively. The estimated future
payments for these required obligations are as follows (in
thousands):
|
|
|
|
|
|
|
Amount
|
|
|
Three months ending December 31, 2008
|
|
$
|
1,999
|
|
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
|
|
|
8,150
|
|
Less amounts representing interest at 3.51%
|
|
|
1,071
|
|
|
|
|
|
|
Accrued environmental liabilities at September 30, 2008
|
|
$
|
7,079
|
|
|
|
|
|
|
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 intending to limit the amount of
sulfur in diesel and gasoline. The EPA has granted the
Companys petition for a technical hardship waiver with
respect to the date for compliance in meeting the
sulfur-lowering standards. CVR spent approximately
$16.8 million in 2007, $79.0 million in 2006 and
$27.0 million in 2005 to comply with the low-sulfur rules.
CVR spent $10.1 million in the first nine months of 2008
and, based on information currently available, anticipates
spending approximately $6.4 million in the last three
months of 2008, $41.6 million in 2009, and
$5.0 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 three month periods ended September 30, 2008 and
2007, capital expenditures were $5,481,000 and $16,195,000,
respectively. For the nine month periods ended
September 30, 2008 and 2007, capital expenditures were
$34,842,000 and $102,775,000, respectively. These expenditures
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.
24
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(14)
|
Derivative
Financial Instruments
|
Gain (loss) on derivatives, net consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Realized loss on swap agreements
|
|
$
|
(33,794
|
)
|
|
$
|
(45,352
|
)
|
|
$
|
(107,747
|
)
|
|
$
|
(142,567
|
)
|
Unrealized gain (loss) on swap agreements
|
|
|
98,947
|
|
|
|
90,196
|
|
|
|
69,051
|
|
|
|
(98,294
|
)
|
Realized gain (loss) on other agreements
|
|
|
10,811
|
|
|
|
(1,247
|
)
|
|
|
(10,203
|
)
|
|
|
(8,834
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
1,258
|
|
|
|
726
|
|
|
|
634
|
|
|
|
(837
|
)
|
Realized gain (loss) on interest rate swap agreements
|
|
|
(891
|
)
|
|
|
965
|
|
|
|
(1,316
|
)
|
|
|
3,282
|
|
Unrealized gain (loss) on interest rate swap agreements
|
|
|
375
|
|
|
|
(4,756
|
)
|
|
|
(889
|
)
|
|
|
(4,662
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives, net
|
|
$
|
76,706
|
|
|
$
|
40,532
|
|
|
$
|
(50,470
|
)
|
|
$
|
(251,912
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CVR is subject to crude oil and finished goods price
fluctuations caused by supply and demand conditions, weather,
economic conditions, and other factors. To manage this 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. CVR is also
subject to interest rate fluctuations. To manage interest rate
risk and to meet the requirements of the credit agreements CALLC
entered into an interest rate swap, as further described below
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. For the purposes of
segment reporting, realized and unrealized gains or losses
related to the commodity derivative contracts are reported in
the Petroleum Segment.
Cash
Flow Swap
At September 30, 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 16, 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 agreement. 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. At September 30, 2008 the notional
open amounts under the swap agreements were
23,883,250 barrels of crude oil, 501,548,250 gallons of
heating oil and 501,548,250 gallons of unleaded gasoline.
25
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Interest
Rate Swap
At September 30, 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 $250,000,000. Half of the agreements are
held with a related party (as described in Note 16,
Related Party Transactions), and the other half are
held with a financial institution that is a lender under
CRLLCs long-term debt agreement. The swap agreements carry
the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Fixed
|
|
Period Covered
|
|
Amount
|
|
|
Interest Rate
|
|
|
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 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.
|
|
(15)
|
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 3 to the Condensed Consolidated Financial
Statements. As of September 30, 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)
|
26
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table sets forth the assets and liabilities
measured at fair value on a recurring basis, by input level, as
of September 30, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Cash Flow Swap
|
|
|
|
|
|
$
|
(264,536
|
)
|
|
|
|
|
|
$
|
(264,536
|
)
|
Interest Rate Swap
|
|
|
|
|
|
|
(2,758
|
)
|
|
|
|
|
|
|
(2,758
|
)
|
Other Derivative Agreements
|
|
|
|
|
|
|
4,726
|
|
|
|
|
|
|
|
4,726
|
|
The Companys derivative contracts giving rise to assets or
liabilities under Level 2 are valued using pricing models
based on other significant observable inputs.
|
|
(16)
|
Related
Party Transactions
|
Management
Services Agreements
GS Capital Partners V Fund, L.P. and related entities (GS) and
Kelso Investment Associates VII, L.P. and related entity (Kelso)
through their majority ownership of CALLC and CALLC II 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,
the Company recorded $500,000 and $1,582,000 in selling,
general, and administrative expenses (exclusive of depreciation
and amortization) for the three and nine months ended
September 30, 2007, respectively. As these agreements were
terminated on October 26, 2007 there have been no expenses
recorded in 2008.
Cash
Flow Swap
CALLC entered into certain crude oil, heating oil and gasoline
swap agreements with a subsidiary of GS,
J. Aron & Company (J. Aron). Additional swap
agreements with J. Aron were entered into on June 16, 2005,
with an expiration date of June 30, 2010 (as described in
Note 14, Derivative Financial Instruments).
These agreements were assigned to CRLLC on June 24, 2005.
Gains totaling $65,153,000 and $44,844,000 were recognized
related to these swap agreements for the three months ended
September 30, 2008 and 2007, respectively, and are
reflected in gain (loss) on derivatives, net in the Consolidated
Statements of Operations. For the nine months ended
September 30, 2008 and 2007 the Company recognized losses
of $38,696,000 and $240,861,000, respectively, which are
reflected in gain (loss) on derivatives, net in the Consolidated
Statements of Operations. In addition, the Consolidated Balance
Sheet at September 30, 2008 and December 31, 2007
includes liabilities of $236,633,000 and $262,415,000,
respectively, included in current payable to swap counterparty,
and $27,903,000 and $88,230,000, respectively, included in
long-term payable to swap counterparty.
J.
Aron Deferrals
As a result of the flood and the temporary cessation of business
operations in 2007, the Company entered into three separate
deferral agreements for amounts owed to J. Aron. The amount
deferred, excluding accrued interest, totaled
$123.7 million. Of the original deferred balances,
$36.2 million has been repaid as of September 30,
2008. These deferred payment amounts are included in the
Consolidated Balance Sheet at September 30, 2008 in current
payable to swap counterparty. The deferred balance owed to the
GS subsidiary, excluding accrued interest payable, totaled
$87.5 million at September 30, 2008. Approximately
$0.5 million of accrued interest payable related to the
deferred payments is included in other current liabilities at
September 30, 2008.
On July 29, 2008, CRLLC entered into a revised letter
agreement with J. Aron to defer $87.5 million of the
deferred payment amounts under the 2007 deferral agreements. On
August 29, 2008, the Company paid
27
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$36.2 million of the balance to J. Aron, as well as
$7.1 million in accrued interest. Subsequent to the quarter
end, the Company paid an additional $15.0 million through
use of proceeds received on the environmental insurance policy.
The deferral agreement was further amended on October 11,
2008 and the outstanding balance of $72.5 million on that
date was further deferred to July 31, 2009. Additional
proceeds of $9.8 million received under the property
insurance policy subsequent to October 11, 2008, were used
to pay down the principle balance on the deferral amount to
$62.7 million as of November 6, 2008. Under the most
recent deferral, the unpaid deferred amounts and all accrued and
unpaid interest are due and payable in full on July 31,
2009. However, all accrued interest through December 15,
2008 must be paid on that day. Interest will accrue on the
amounts deferred at the rate of (i) LIBOR plus 2.75% until
December 15, 2008 and (ii) LIBOR plus 5.00%-7.50%
(depending on J. Arons cost of capital) from
December 15, 2008 through the date of payment. CRLLC must
make prepayments of $5.0 million for the quarters ending
March 31, 2009 and June 30, 2009 to reduce the
deferred amounts. To the extent that CRLLC or any of its
subsidiaries receives net insurance proceeds related to the July
2007 flood that are not required to be used to prepay
CRLLCs credit agreement or be invested pursuant to the
terms of CRLLCs credit agreement, all net insurance
proceeds will be used to prepay the deferred amounts. GS and
Kelso each agreed to guarantee one half of the deferral amount
of $72.5 million.
Interest
Rate Swap
On June 30, 2005, CALLC entered into three interest-rate
swap agreements with J. Aron (as described in Note 14,
Derivative Financial Instruments). Losses totaling
$256,000 and $1,894,000 were recognized related to these swap
agreements for the three months ended September 30, 2008
and 2007, respectively, and are reflected in gain (loss) on
derivatives, net in the Consolidated Statements of Operations.
For the nine months ended September 30, 2008 and 2007, the
Company recognized losses totaling $1,107,000 and $683,000,
respectively related to these swap agreements which are
reflected in gain (loss) on derivatives, net, in the
Consolidated Statements of Operations. In addition, the
Consolidated Balance Sheet at September 30, 2008 and
December 31, 2007 includes $786,000 and $371,000,
respectively, in other current liabilities and $590,000 and
$557,000, respectively, in other long-term liabilities related
to the same agreements.
Crude
Oil Supply Agreement
Coffeyville Resources Refining & Marketing, LLC
(CRRM), a subsidiary of the Company, is a counterparty to a
crude oil supply agreement with J. Aron. Under the agreement,
the parties agreed to negotiate the cost of each barrel of crude
oil to be purchased from a third party, and CRRM agreed to pay
J. Aron 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 Company recorded $26,407,000 and $360,000 on
the Consolidated Balance Sheets at September 30, 2008 and
December 31, 2007, respectively, in prepaid expenses and
other current assets for the prepayment of crude oil. In
addition, $41,111,000 and $43,773,000 were recorded in inventory
and $24,315,000 and $42,666,000 were recorded in accounts
payable at September 30, 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 periods ended
September 30, 2008 and 2007 totaled $966,006,000 and
$251,958,000, respectively. For the nine months ended
September 30, 2008 and 2007, the Company recognized
expenses of $2,640,135,000 and $772,872,000, respectively,
associated with this agreement included in cost of product sold
(exclusive of depreciation and amortization).
Cash
and Cash Equivalents
The Company opened a highly liquid money market account with
average maturities of less than 90 days within the Goldman
Sachs fund family in September 2008. As of September 30,
2008, the balance in the account was approximately
$51.0 million.
28
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 price
received by the fertilizer segment for UAN (subject to a UAN
based price ceiling and floor) and a coke price index for 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 $3,353,000 and $680,000 for the
three months ended September 30, 2008 and 2007,
respectively. Intercompany sales included in petroleum net sales
were $8,959,000 and $2,560,000 for the nine months ended
September 30, 2008 and 2007, respectively.
Intercompany cost of product sold (exclusive of depreciation and
amortization) for the hydrogen sales described below under
Nitrogen Fertilizer was $40,000 and
$2,593,000 for the three months ended September 30, 2008
and 2007, respectively. The intercompany cost of product sold
(exclusive of depreciation and amortization) for the hydrogen
sales described below under Nitrogen
Fertilizer was $7,932,000 and $10,611,000 for the nine
months ended September 30, 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 $3,364,000 and $631,000 for the
three months ended September 30, 2008 and 2007,
respectively. Intercompany cost of product sold (exclusive of
depreciation and amortization) for the coke transfer described
above was $8,235,000 and $2,597,000 for the nine months ended
September 30, 2008 and 2007, respectively.
Beginning in 2008, the Nitrogen Fertilizer Segment changed the
method of classification of intercompany hydrogen sales to the
Petroleum Segment. In 2008, these amounts have been 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 deprecation
and amortization). For the quarters ended September 30,
2008 and 2007, the net sales generated from intercompany
hydrogen sales were $40,000 and $2,593,000, respectively. For
the nine months ended September 30, 2008 and 2007, hydrogen
sales were $7,932,000 and $10,611,000, respectively. As noted
above, the net sales of $2,593,000 and $10,611,000 were included
as a reduction to the cost of product sold (exclusive of
depreciation and amortization) for the three and nine months
ended September 30, 2007. As these intercompany sales are
eliminated, there is no financial statement impact on the
consolidated financial statements.
29
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Segment
The Other Segment reflects all intercompany eliminations,
including significant intercompany eliminations of receivables
and payables between the segments, 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
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated()
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
Net sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,510,287
|
|
|
$
|
545,902
|
|
|
$
|
4,137,888
|
|
|
$
|
1,707,344
|
|
Nitrogen Fertilizer
|
|
|
74,155
|
|
|
|
40,756
|
|
|
|
195,557
|
|
|
|
115,091
|
|
Intersegment eliminations
|
|
|
(3,531
|
)
|
|
|
(680
|
)
|
|
|
(17,028
|
)
|
|
|
(2,561
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,580,911
|
|
|
$
|
585,978
|
|
|
$
|
4,316,417
|
|
|
$
|
1,819,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,437,742
|
|
|
$
|
450,153
|
|
|
$
|
3,758,383
|
|
|
$
|
1,319,223
|
|
Nitrogen Fertilizer
|
|
|
6,156
|
|
|
|
3,719
|
|
|
|
21,947
|
|
|
|
9,908
|
|
Intersegment eliminations
|
|
|
(3,543
|
)
|
|
|
(630
|
)
|
|
|
(16,304
|
)
|
|
|
(2,596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,440,355
|
|
|
$
|
453,242
|
|
|
$
|
3,764,026
|
|
|
$
|
1,326,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
37,132
|
|
|
$
|
29,544
|
|
|
$
|
120,106
|
|
|
$
|
170,685
|
|
Nitrogen Fertilizer
|
|
|
19,443
|
|
|
|
14,896
|
|
|
|
59,361
|
|
|
|
48,122
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
56,575
|
|
|
$
|
44,440
|
|
|
$
|
179,467
|
|
|
$
|
218,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
(1,014
|
)
|
|
$
|
28,595
|
|
|
$
|
7,888
|
|
|
$
|
30,630
|
|
Nitrogen Fertilizer
|
|
|
10
|
|
|
|
1,892
|
|
|
|
27
|
|
|
|
1,996
|
|
Other
|
|
|
187
|
|
|
|
1,705
|
|
|
|
927
|
|
|
|
1,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(817
|
)
|
|
$
|
32,192
|
|
|
$
|
8,842
|
|
|
$
|
34,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
15,647
|
|
|
$
|
6,616
|
|
|
$
|
46,797
|
|
|
$
|
29,695
|
|
Nitrogen Fertilizer
|
|
|
4,484
|
|
|
|
3,586
|
|
|
|
13,447
|
|
|
|
12,377
|
|
Other
|
|
|
478
|
|
|
|
279
|
|
|
|
1,080
|
|
|
|
601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
20,609
|
|
|
$
|
10,481
|
|
|
$
|
61,324
|
|
|
$
|
42,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
20,187
|
|
|
$
|
19,417
|
|
|
$
|
185,683
|
|
|
$
|
122,287
|
|
Nitrogen Fertilizer
|
|
|
46,483
|
|
|
|
13,834
|
|
|
|
95,645
|
|
|
|
34,863
|
|
Other
|
|
|
5,339
|
|
|
|
(1,663
|
)
|
|
|
991
|
|
|
|
(1,744
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
72,009
|
|
|
$
|
31,588
|
|
|
$
|
282,319
|
|
|
$
|
155,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
10,235
|
|
|
$
|
24,775
|
|
|
$
|
49,364
|
|
|
$
|
235,862
|
|
Nitrogen Fertilizer
|
|
|
7,360
|
|
|
|
952
|
|
|
|
16,479
|
|
|
|
3,597
|
|
Other
|
|
|
243
|
|
|
|
(85
|
)
|
|
|
1,630
|
|
|
|
236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
17,838
|
|
|
$
|
25,642
|
|
|
$
|
67,473
|
|
|
$
|
239,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Note 2 to condensed consolidated financial statements. |
30
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of September 30,
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,307,605
|
|
|
$
|
1,277,124
|
|
Nitrogen Fertilizer
|
|
|
620,072
|
|
|
|
446,763
|
|
Other
|
|
|
(2,196
|
)
|
|
|
144,469
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,925,481
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
42,806
|
|
|
$
|
42,806
|
|
Nitrogen Fertilizer
|
|
|
40,969
|
|
|
|
40,969
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
83,775
|
|
|
$
|
83,775
|
|
|
|
|
|
|
|
|
|
|
On October 10, 2008, the Company, through its wholly-owned
subsidiaries, entered into ten year agreements with Magellan
Pipeline Company LP (Magellan), which agreements will allow for
the transportation of an additional 20,000 barrels per day
of refined fuels from the Companys Coffeyville, Kansas
refinery and the storage of refined fuels on the Magellan system.
On June 19, 2008, CVR filed a registration statement with
the SEC in connection with a proposed offering of
$125.0 million aggregate principal amount of CVRs
Convertible Senior Notes due 2013. CVR filed an amendment to the
aforementioned registration statement on August 25, 2008.
CVR requested that the SEC withdraw the registration statement
on November 4, 2008. The Company will record a write-off of
previously deferred costs associated with the offering of
approximately $1.5 million in the fourth quarter of 2008.
On November 3, 2008, following a period of discussions with
the City of Coffeyville, Kansas (the City) regarding CRNFs
electricity contract and in light of the Citys contention
that CRNF had constructively terminated the contract, CRNF filed
a lawsuit against the City in the District Court of Johnson
County, Kansas. Under the contract CRNF must make a series of
future payments for electrical generation and transmission and
city margin based upon agreed upon rates. The City recently
began charging a higher rate for electricity than what had been
agreed to in the contract. The Company filed the lawsuit to have
the contract enforced as written and to recover other damages.
The Company believes that if the City is successful in the
lawsuit, the higher electricity costs that it would be allowed
to charge would not be material to the Companys results of
operations.
31
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion and analysis should be read in
conjunction with the consolidated financial statements and
related notes and with the statistical information and financial
data appearing in this Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2008 as well as the
Companys Annual Report on
Form 10-K/A
for the year ended December 31, 2007. Results of operations
for the three and nine month periods ended September 30,
2008 are not necessarily indicative of results to be attained
for any other period.
Forward-Looking
Statements
This
Form 10-Q,
including this Managements Discussion and Analysis of
Financial Condition and Results of Operations, contains
forward-looking statements as defined by the SEC.
Such statements are those concerning contemplated transactions
and strategic plans, expectations and objectives for future
operations. These include, without limitation:
|
|
|
|
|
statements, other than statements of historical fact, that
address activities, events or developments that we expect,
believe or anticipate will or may occur in the future;
|
|
|
|
statements relating to future financial performance, future
capital sources and other matters; and
|
|
|
|
any other statements preceded by, followed by or that include
the words anticipates, believes,
expects, plans, intends,
estimates, projects, could,
should, may, or similar expressions.
|
Although we believe that our plans, intentions and expectations
reflected in or suggested by the forward-looking statements we
make in this
Form 10-Q,
including this Managements Discussion and Analysis of
Financial Condition and Results of Operations, are reasonable,
we can give no assurance that such plans, intentions or
expectations will be achieved. These statements are based on
assumptions made by us based on our experience and perception of
historical trends, current conditions, expected future
developments and other factors that we believe are appropriate
in the circumstances. Such statements are subject to a number of
risks and uncertainties, many of which are beyond our control.
You are cautioned that any such statements are not guarantees of
future performance and actual results or developments may differ
materially from those projected in the forward-looking
statements as a result of various factors, including but not
limited to those set forth under Risk Factors
attached hereto as Exhibit 99.1.
All forward-looking statements contained in this
Form 10-Q
speak only as of the date of this document. We undertake no
obligation to update or revise publicly any forward-looking
statements to reflect events or circumstances that occur after
the date of this
Form 10-Q,
or to reflect the occurrence of unanticipated events.
Restatement
of September 30, 2007 Financial Statements
As previously disclosed in our amended Annual Report on
Form 10-K/A,
the Company determined that the 2007 fiscal year financial
information contained certain errors resulting from accounting
errors in the third and fourth quarters of 2007. The errors
arose principally from the calculation of the cost of crude oil
purchased by the Company and associated transactions. We did not
amend our previously filed Quarterly Report on
Form 10-Q
for the period ended September 30, 2007. The financial
information presented in this report for September 30, 2008
contains restated information for the September 30, 2007
interim period. The effect of the restatement on our period
ended September 30, 2007 is set forth in tables in
Note 2 to the condensed consolidated financial statements.
Company
Overview
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 ammonia
and urea ammonia nitrate, or UAN, fertilizers.
We operate under two business segments: petroleum and nitrogen
fertilizer. Our petroleum business includes a
115,000 barrel per day, or 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
32
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 into tanker
trucks for distribution 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 (Magellan) 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.
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.
The nitrogen fertilizer segment consists of our interest in CVR
Partners, LP, a limited partnership controlled by our
affiliates, which operates a nitrogen fertilizer plant and the
nitrogen fertilizer business. The nitrogen fertilizer business
is one of the low cost producers and marketers of ammonia and
UAN in North America, given our use of pet coke and assuming
relatively high natural gas prices. The fertilizer plant is the
only commercial facility in North America utilizing a coke
gasification process to produce nitrogen fertilizers. The use of
low cost by-product pet coke from our adjacent oil refinery as
feedstock (rather than natural gas) to produce hydrogen provides
the facility with a significant competitive advantage during
periods of high and volatile natural gas prices. The
plants competition utilizes natural gas to produce
ammonia. During periods of high and volatile natural gas prices,
the plant is a low cost producer of fertilizer products in North
America. Recognizing the fixed cost nature of our fertilizer
business, the competitive advantage decreases proportionately as
natural gas prices decline. With the recent decline in natural
gas prices, the historic cost advantage that the plant has had
is now beginning to narrow.
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. 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 CVRs 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. The balance of the net proceeds received were used for
general corporate purposes.
In connection with the initial public offering, we also became
the indirect owner of Coffeyville Resources, LLC (CRLLC) and all
of its refinery assets. This was accomplished by CVR issuing
62,866,720 shares of its common stock to certain entities
controlled by its majority stockholders pursuant to a stock
split in exchange for the interests in certain subsidiaries of
CALLC. Immediately following the completion of the offering,
there were 86,141,291 shares of common stock outstanding,
excluding shares of non-vested stock issued.
CVR
Energys Proposed Secondary Offering
CVR filed a registration statement with the SEC on June 19,
2008 in which its majority stockholders and chairman proposed to
offer 10 million shares of the Companys common stock.
The Company announced on July 30, 2008 that the majority
stockholders elected not to proceed with the proposed secondary
offering at that time due to then-existing market conditions.
The registration statement remains on file with the SEC, and the
selling stockholders may elect to proceed with the equity
offering in the future.
CVR
Energys Proposed Convertible Debt Offering
CVR filed a registration statement with the SEC on June 19,
2008 in connection with a proposed offering of
$125.0 million aggregate principal amount of CVRs
Convertible Senior Notes due 2013. CVR filed an amendment to
this registration statement on August 25, 2008. CVR
requested that the SEC withdraw the registration statement on
November 4, 2008. The Company will record a write-off of
previously deferred costs associated with the offering of
approximately $1.5 million in the fourth quarter of 2008.
33
Major
Influences on Results of Operations
Petroleum Business. Our earnings and cash flow
from petroleum operations are primarily affected by the
relationship between refined product prices and the prices for
crude oil and other feedstocks such as liquid petroleum gas and
natural gas. The prices of crude oil and refined products have
fluctuated substantially in recent periods and specifically
during the three months ended September 30, 2008. The cost
to acquire feedstocks, and the price for which refined products
are ultimately sold, depend on market factors that are typically
beyond our control. These include the overall supply of, and
demand for, crude oil, gasoline, and other refined products.
These factors are influenced by changes in domestic and foreign
economics, weather conditions, domestic and foreign political
affairs, foreign and domestic 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 inventory, crude oil
price movements can cause significant fluctuations in the
valuation of our in-process inventories and finished products
in-process inventories. The effect of changes in crude oil
prices on our results of operations is also 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 significant fluctuations. An
expansion or upgrade of refining capacity, price volatility,
international political and economic developments, and other
factors beyond our control are likely to continue to play a
significant role in refining industry economics. These factors
can impact, among other things, the level of inventories in the
market, contributing to 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.
In order to assess our operating performance, we compare our
refining margin, calculated as the difference between net sales
and cost of product sold (exclusive of depreciation and
amortization), against a widely used industry refining margin
benchmark. The industry standard that the Company uses assumes
that two barrels of benchmark light sweet crude oil are
converted into one barrel of conventional gasoline and one
barrel of distillate fuel oil. 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.
Crude oil prices rose to historic highs during the first part of
July 2008, but declined significantly by the end of the third
quarter. These prices continued to decline in October and could
have a significant impact on our net income due to the
unfavorable impact expected to occur in the fourth quarter of
2008 caused by our use of the FIFO accounting method for
inventory. West Texas Intermediate crude oil averaged $113.52
per barrel for the nine months ending September 30, 2008,
as compared to $66.19 per barrel during the comparable period in
2007. WTI spiked to $145.29 per barrel on July 3, 2008 and
moved downward to $100.64 per barrel on September 30, 2008,
averaging $118.22 per barrel for the third quarter. WTI was
$60.77 per barrel on November 6, 2008.
Every barrel of crude oil that we process yields approximately
88% high performance transportation fuels and distillates, and
approximately 12% heavy oils and solids. Volumetric losses (lost
volume typically resulting from evaporation or some chemical
change) also occur during the refining process. As crude oil
costs increased, sales prices for many byproducts did not
increase in the same proportions, resulting in lower gross
margin during the periods of rising prices.
When refined product prices increase proportionally with crude
oil prices, the loss on byproduct sales and volumetric loss on
crude oil processed should be more than offset by refined fuel
margins. With the recent crude price volatility, refined fuels
have failed to keep pace with crude oil costs as evidence by the
narrowed 2-1-1 crack spread as a percentage of crude oil prices.
For the third quarter of 2007 the 2-1-1 crack spread as a
percentage of crude oil price was approximately 16.1% compared
to 11.3% in the third quarter of 2008.
34
Although crack spreads are relatively low compared to historical
levels as a percentage of crude oil price, the absolute value of
the NYMEX 2-1-1 crack spread for the third quarter of 2008 was
$13.33 per barrel, which is well above the fixed value of our
Cash Flow Swap for the quarter of $7.87 per barrel. Because the
actual NYMEX 2-1-1 crack spread was greater than the Cash Flow
Swap fixed value, we incurred a realized loss of
$33.8 million for the quarter on 6.2 million hedged
barrels. The absolute value NYMEX 2-1-1 crack spread will
continue to have a significant impact on our financial results
due to the Cash Flow Swap until June 30, 2009, when the
number of barrels subject to the Cash Flow Swap decreases from
approximately 6.0 million barrels per quarter to
1.5 million barrels per quarter.
While the 2-1-1 crack spread is a benchmark for our refinery
margin, we have certain feedstock costs
and/or
logistical advantages as compared to a benchmark refinery. Our
product yield is less than total refinery throughput, and 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 that
has historically cost less than WTI crude oil, a light sweet
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. The spread is referred
to as our consumed crude differential, which can significantly
impact our refinery margin. Our differential will move
directionally with changes in the West Texas Sour (WTS)
differential to WTI, and the Western Canadian Select (WCS)
differential to WTI. Both of these differentials indicate the
relative price of heavier, more sour, slate to a lighter sweet
WTI. The WTI-WCS differential for the third quarter of 2008 was
$18.69 a barrel as compared to $25.80 a barrel in the third
quarter of 2007. As a percentage of WTI, however, this metric
averaged 34.3% of WTI in the 2007 period compared to 15.8% in
the third quarter of 2008. 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.
Our petroleum business has been impacted by lower refining
margins, reduced demand and our Cash Flow Swap. While improving
somewhat from their recent lows, midcontinent refining margins
remain below historical metrics when factoring in the high cost
of crude. Increased throughput at our refinery provides some
offset of these factors. Historically, the strongest refining
margins occur during the second and third quarters based on
gasoline and diesel demand, and while crude oil prices have
declined sharply from recent highs, crack spreads have not yet
improved in line with the crude price declines due to continuing
gasoline demand weakness.
We produce a significant volume of high value products, such as
gasoline and distillates. Approximately 40% of our product slate
is ultra low sulfur diesel, which provides us with income tax
credits and is currently selling at higher margins than
gasoline. Gasoline production was approximately 45.3% of our
third quarter production, up from 44.4% in the third quarter of
2007. We continue to maximize distillate production, which
comprised 39.1% of our production in the third quarter of 2008
compared to 40.2% in the third quarter of 2007. The balance of
our production is devoted to other liquids and products,
including petroleum coke which is used by the nitrogen
fertilizer business. We benefit from the fact that our marketing
region consumes more refined products than it produces,
resulting in market prices high enough to cover the logistics
cost for U.S. Gulf Coast refineries to ship into our region
to meet demand. The result of this logistical advantage of our
refinery operations typically yields crack spreads that are
favorable to those depicted by the 2-1-1 model. 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. The Group 3 basis
differential averaged $3.65 a barrel in the third quarter of
2008, compared to $9.46 a barrel in the comparable period of
2007.
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 mainly of electricity and natural gas. We are
therefore sensitive to the price movement of these energy
sources.
Consistent, safe, and reliable operations at our refinery are
key to our financial performance and results of operations.
Unplanned downtime 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
35
into account the margin environment, the availability of
resources to perform needed maintenance, feedstock costs and
other factors.
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 the
majority of the pet coke feedstock needed by the nitrogen
fertilizer business. 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 lower 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.
Third quarter 2008 NYMEX natural gas prices averaged $8.99 per
million Btus compared with $6.24 per million Btus for the
comparable period in 2007. This rise in natural gas prices
implies a minimum increase of $90.75 per ton in production costs
for natural gas based North American producers while our
production cost remains substantially unchanged.
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. It takes approximately
.41 tons of ammonia to produce 1 ton of 32% UAN. UAN production
is a major contributor to our profitability. We continue with
plans for full conversion of our ammonia product line to UAN and
for expansion of total UAN capacity from 2,000 to 3,000 tons per
day. 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, less the costs to
ship.
Average prices for both ammonia and UAN for the three and nine
months ended September 30, 2008 reflect strong demand for
these products during the first nine months of 2008. Ammonia
plant gate prices averaged $685 per ton for the third quarter
ended September 30, 2008, compared to $363 per ton during
the comparable period in 2007. UAN prices averaged $324 per ton
for the third quarter ended September 30, 2008, compared to
$234 per ton during the comparable 2007 period. While there has
been some recent price erosion for all fertilizer products,
fundamental demand drivers such as forecasted commodity grain
stock to use ratios and estimated 2009 acres planted remain
strong. Our order book as of September 30, 2008 contains an
average net back price of ammonia and UAN of $786 and $376 per
ton, respectively. Actual future prices will depend on supply
and demand and other factors described herein.
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
36
natural gas-based fertilizer plants. Major direct operating
expenses include electrical energy, employee labor, maintenance,
including contract labor, and outside services. These costs
comprise the fixed costs associated with the fertilizer plant.
The nitrogen fertilizer business generally undergoes a facility
turnaround every two years. The turnaround typically lasts
15-20 days
and requires approximately $2-3 million in direct costs per
turnaround. The facility completed a scheduled turnaround in
October 2008. As of September 30, 2008, $0.1 million
had been incurred. It is estimated that approximately
$3.1 million of costs were incurred in October associated
with the turnaround.
Factors
Affecting Comparability of Our Financial Results
Our historical results of operations for the periods presented
may not be comparable with prior periods or to our results of
operations in the future for the reasons discussed below.
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.
As a result of the flooding, our refinery and nitrogen
fertilizer facilities stopped operating on June 30, 2007.
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. The nitrogen fertilizer
facility initiated startup at its production facility on
July 13, 2007. Due to the down time, we experienced a
significant revenue loss attributable to the property damage
during the period when the facilities were not in operation.
Total gross costs incurred and recorded as of September 30,
2008 related to the third party costs to repair the refinery and
fertilizer facilities were approximately $77.0 million and
$4.4 million, respectively.
In addition, 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 substantially completed remediating
the damage caused by the crude oil discharge in July 2008 and
expect any remaining minor remedial actions to be completed by
December 31, 2008. In 2007, the Company 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. In
the third quarter of 2008, the Company received
$13.0 million under its property insurance policy and
$15.0 million was received from its primary environmental
liability insurance carrier, which when added to the prior
$10.0 million paid by that carrier, resulted in payment of
the policy limit under such primary environmental liability
policy of $25.0 million. As of September 30, 2008, the
Company had received $49.5 million in insurance recoveries.
In October 2008, the Company through certain wholly-owned
subsidiaries submitted an advance payment proof of loss to
certain of its insurers for unallocated property damage. The
Company expects to receive an advance payment related thereto in
the amount of approximately $10.1 million. As of
November 6, 2008, the Company has received
$9.8 million of the $10.1 million total, increasing
the total insurance recoveries received from $49.5 million
at September 30, 2008 to $59.3 million as of
November 6, 2008.
The Company received in May 2008 notices of claims from sixteen
private claimants under the Oil Pollution Act in an aggregate
amount of approximately $4.4 million. Subsequently, in
August, 2008, those claimants filed suit against the Company in
the United States District Court for the District of Kansas in
Wichita. We believe that the resolution of these claims will not
have a material adverse effect on our consolidated financial
statements.
As of September 30, 2008, the Company has recorded total
gross costs associated with the repair of, and other matters
relating to, the damage to the Companys facilities and
with third party and property damage remediation incurred due to
the crude oil discharge of approximately $154.6 million.
Total anticipated insurance recoveries of approximately
$104.2 million have been recorded as of September 30,
2008 (of which $49.5 million had already
37
been received as of September 30, 2008 by the Company from
insurance carriers). At September 30, 2008, total accounts
receivable from insurance were $54.7 million. The
receivable balance is segregated between current and long-term
in the Companys Consolidated Balance Sheet in relation to
the nature and classification of the items to be settled. As of
September 30, 2008, $35.4 million of the amounts
receivable from insurers were not anticipated to be collected in
the next twelve months, and therefore has been classified as a
non-current asset.
Below is a summary of the gross cost arising from the flood and
crude oil discharge and a reconciliation of the related
insurance receivable as of September 30, 2008 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Total
|
|
|
September 30, 2008
|
|
|
September 30, 2008
|
|
|
Total gross costs incurred
|
|
$
|
154.6
|
|
|
$
|
1.0
|
|
|
$
|
7.8
|
|
Total insurance receivable
|
|
|
(104.2
|
)
|
|
|
(1.8
|
)
|
|
|
1.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with the flood
|
|
$
|
50.4
|
|
|
$
|
(0.8
|
)
|
|
$
|
8.9
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
Reconciliation
|
|
|
Total insurance receivable
|
|
$
|
104.2
|
|
Less insurance proceeds received
|
|
|
(49.5
|
)
|
|
|
|
|
|
Insurance receivable as of September 30, 2008
|
|
$
|
54.7
|
|
The flood significantly impacted our financial results for the
third quarter of 2007 with minimal impact on our third quarter
2008 results.
Refinancing
and Prior Indebtedness
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. Our Statements of Operations for the three and nine
months ended September 30, 2008 include interest expense of
$9.3 million and $30.1 million, respectively, on term
debt of $485.5 million. Interest expense for the three and
nine months ended September 30, 2007 totaled
$18.3 million and $46.0 million, respectively, on term
debt of $821.1 million.
J. Aron
Deferrals
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, CRLLC entered into several
deferral agreements with J. Aron & Company (J. Aron)
with respect to the Cash Flow Swap, which is a series of
commodity derivative arrangements whereby if crack spreads fall
below a fixed level, J. Aron agreed to pay the difference to us,
and if crack spreads 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.
On July 29, 2008, CRLLC entered into a revised letter
agreement with J. Aron to defer further $87.5 million of
the deferred payment amounts under the 2007 deferral agreements
to December 15, 2008. On August 29, 2008, in
accordance with the additional deferral agreement, we paid
$36.2 million to J. Aron, as well as $7.1 million in
accrued interest as of that date resulting in a remaining
balance due of $87.5 million. As of September 30,
2008, the outstanding balance due was $87.5 million and the
related accrued interest was $0.5 million.
Subsequent to the September 30, 2008 quarter end, we paid
an additional $15.0 million through use of proceeds
received under our environmental insurance policy An Amended and
Restated Settlement Deferral Letter was signed on
October 11, 2008 and the remaining balance of
$72.5 million at that time was further deferred until
July 31, 2009. Additional insurance recoveries have been
received from our property insurance carriers since the
October 11, 2008 deferral. As of November 6, 2008, the
principal deferral balance after the additional payments from
insurance proceeds was $62.7 million.
38
Under this most recent deferral, the unpaid deferred amounts and
all accrued and unpaid interest are due and payable in full on
July 31, 2009. However, all accrued interest through
December 15, 2008 must be paid on that day. Interest will
accrue on the amounts deferred at the rate of (i) LIBOR
plus 2.75% until December 15, 2008 and (ii) LIBOR plus
5.00%-7.50% (depending on J. Arons cost of capital) from
December 15, 2008 through the date of payment. CRLLC must
make prepayments of $5.0 million for the quarters ending
March 31, 2009 and June 30, 2009 to reduce the
deferred amounts. To the extent that CRLLC or any of its
subsidiaries receives net insurance proceeds related to the July
2007 flood that they are not required to use to prepay
CRLLCs credit agreement or invest pursuant to the terms of
CRLLCs credit agreement, all net insurance proceeds will
be used to prepay the deferred amounts. GS and Kelso each agreed
to guarantee one half of the deferred payment obligations.
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, CRLLC.
The reporting entity of the organization (CALLC) was also a
partnership. Immediately prior to the closing of our initial
public offering, CRLLC became an indirect, wholly-owned
subsidiary of CVR Energy, Inc. 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.
2007
Turnaround
In April 2007, we completed a planned turnaround of our refining
plant at a total cost approximating $80.4 million, which
included $76.8 million recorded in the nine month period
ended September 30, 2007. No amounts were incurred for the
three months ended September 30, 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 the first and second quarter of 2007
and had no impact on our 2008 results.
Cash Flow
Swap
On June 16, 2005, CALLC entered into the Cash Flow Swap
with J. Aron. The Cash Flow Swap was subsequently assigned from
CALLC to CRLLC on June 24, 2005. The derivative took the
form of three NYMEX swap agreements whereby if absolute (i.e.,
in dollar terms, not 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 57% and 14% of crude oil
capacity for the periods October 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 executed crude
oil capacity, for the period from April 1, 2008 through
December 31, 2008, and we are allowed to terminate the Cash
Flow Swap in 2009 and 2010, at which time the unrealized loss
would become a fixed obligation. 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 Statement of Operations reflects all the realized and
unrealized gains and losses from this swap which can create
significant changes between periods. The recent environment of
high and rising crude oil prices 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 a material negative impact on our
earnings through September 30, 2008. As a result of our
position in the Cash Flow Swap, we paid J. Aron
$33.8 million on October 7, 2008 with respect to the
quarter ending September 30, 2008. For the three and nine
months ended September 30, 2008 the Company recognized gain
(loss) on derivatives, net, of $76.7 million and
$(50.5) million, respectively, in the Statements of
Operations, including realized and unrealized gain (loss) on the
Cash Flow Swap of $65.2 million in the three months ended
September 30, 2008 and $(38.7) million in the nine
months ended September 30, 2008. For the three and nine
months ended September 30, 2007 the Company recognized a
gain (loss) on derivatives, net, of $40.5 million and
$(251.9) million, respectively, in the Statements of
Operations. As of September 30, 2008
39
the Companys Consolidated Balance Sheet reflects a payable
to swap counterparty of $264.5 million compared to
$350.6 million as of December 31, 2007.
Share-Based
Compensation
The Company accounts for awards under its Phantom Unit
Appreciation Plan as liability based awards. In accordance with
FAS 123(R), the expense associated with these awards is
based on the current fair value of the awards which is derived
from the Companys stock price as remeasured at each
reporting date until the awards are settled.
Also, in conjunction with the initial public offering in October
2007, the override units of CALLC were modified and split evenly
into override units of CALLC and CALLC II. As a result of the
modification, the awards were no longer accounted for as
employee awards and became subject to the accounting guidance in
EITF 00-12
and
EITF 96-18.
In accordance with that accounting guidance, the expense
associated with the awards is based on the current fair value of
the awards which is derived from the Companys common stock
price as remeasured at each reporting date until the awards
vest. Prior to October 2007, the expense associated with the
override units was based on the original grant date fair value
of the awards. For the three and nine months ended
September 30, 2008 the Company reduced the compensation
expense by $25,769,000 and $36,892,000, respectively, for all
share-based compensation awards. For the three and nine months
ended September 30, 2007 the Company increased compensation
expense by $4,502,000 and $11,285,000, respectively, for all
share-based compensation awards.
Income
Taxes
On an interim basis, income taxes are calculated based upon an
estimated annual effective tax rate for the annual period. The
estimated annual effective tax rate changes primarily due to
changes in projected annual pre-tax income (loss) as estimated
at each interim period and due to the significant federal and
state income tax credits projected to be generated. Federal
income tax credits were generated related to the production of
ultra-low sulfur diesel fuel and Kansas state incentives
generated under the High Performance Incentive Program (HPIP) in
2007 and 2008. The projected income tax credits accompanied by
increasing projected pre-tax loss for 2007 significantly
impacted the estimated annual effective tax rate for 2007 and
generated a significant increase to the income tax benefit
recorded for the three months ended September 30, 2007.
While significant income tax credits of approximately
$60.4 million are estimated to be generated for 2008, the
estimated annual effective tax rate for 2008 is determined based
upon projected pre-tax income rather than projected pre-tax loss.
Property
Tax Assessments
Our results of operations for the three and nine months ending
September 30, 2007 reflect minimal property tax for our
fertilizer facility (due to a tax abatement). Our results of
operations for the three and nine months ended
September 30, 2008 reflect a substantially increased
property tax for our fertilizer facility, resulting from the new
tax assessments by Montgomery County, Kansas with the end of a
ten year tax abatement. We have appealed the assessment received
in 2008 for the fertilizer facility. The refinery was
reappraised in 2007 and 2008 which created a substantial
increase in property tax for the refinery. We have appealed both
the 2007 and 2008 assessment for the refinery and believe that
tax exemptions should apply to any incremental tax which would
be owed as a result of the new assessment in 2008.
Consolidation
of Nitrogen Fertilizer Limited Partnership
Prior to the consummation of our initial public offering in
October 2007, 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 September 30,
2008, 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
40
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.
As of September 30, 2008, the Partnership had distributed
$50 million to CVR.
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 46R).
Using criteria in FIN 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:
|
|
|
|
|
a sale of some or all of our partnership interests to an
unrelated party;
|
|
|
|
a sale of the managing general partner interest to a third party;
|
|
|
|
the issuance by the Partnership of partnership interests to
parties other than us or our related parties; and
|
|
|
|
the acquisition by us of additional partnership interests
(either new interests issued by the Partnership or interests
acquired from unrelated interest holders).
|
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.
41
Results
of Operations
The following tables summarize the financial data and key
operating statistics for CVR and our two operating segments for
the three and nine months ended September 30, 2008 and
2007. The summary financial data for our two operating segments
does not include certain SG&A expenses and depreciation and
amortization related to our corporate offices. The following
data should be read in conjunction with our condensed
consolidated financial statements and the notes thereto included
elsewhere in this
Form 10-Q.
All information in Managements Discussion and
Analysis of Financial Condition and Results of Operations,
except for the balance sheet data as of December 31, 2007,
is unaudited.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Consolidated Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
1,580.9
|
|
|
$
|
586.0
|
|
|
$
|
4,316.4
|
|
|
$
|
1,819.9
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
1,440.3
|
|
|
|
453.2
|
|
|
|
3,764.0
|
|
|
|
1,326.6
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
56.6
|
|
|
|
44.5
|
|
|
|
179.5
|
|
|
|
218.8
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
(7.8
|
)
|
|
|
14.0
|
|
|
|
20.5
|
|
|
|
42.1
|
|
Net costs associated with flood
|
|
|
(0.8
|
)
|
|
|
32.2
|
|
|
|
8.8
|
|
|
|
34.3
|
|
Depreciation and amortization(1)
|
|
|
20.6
|
|
|
|
10.5
|
|
|
|
61.3
|
|
|
|
42.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
72.0
|
|
|
$
|
31.6
|
|
|
$
|
282.3
|
|
|
$
|
155.4
|
|
Other income, net
|
|
|
0.7
|
|
|
|
0.2
|
|
|
|
2.5
|
|
|
|
1.0
|
|
Interest expense and other financing costs
|
|
|
(9.3
|
)
|
|
|
(18.3
|
)
|
|
|
(30.1
|
)
|
|
|
(46.0
|
)
|
Gain (loss) on derivatives, net
|
|
|
76.7
|
|
|
|
40.5
|
|
|
|
(50.5
|
)
|
|
|
(251.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
$
|
140.1
|
|
|
$
|
54.0
|
|
|
$
|
204.2
|
|
|
$
|
(141.5
|
)
|
Income tax (expense) benefit
|
|
|
(40.4
|
)
|
|
|
(42.7
|
)
|
|
|
(51.3
|
)
|
|
|
98.2
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(2)
|
|
$
|
99.7
|
|
|
$
|
11.2
|
|
|
$
|
152.9
|
|
|
$
|
(43.1
|
)
|
Earnings per share, basic
|
|
$
|
1.16
|
|
|
|
|
|
|
$
|
1.77
|
|
|
|
|
|
Earnings per share, diluted
|
|
$
|
1.16
|
|
|
|
|
|
|
$
|
1.77
|
|
|
|
|
|
Weighted average shares, basic
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
|
|
|
|
Weighted average shares, diluted
|
|
|
86,158,791
|
|
|
|
|
|
|
|
86,158,791
|
|
|
|
|
|
Pro forma earnings (loss) per share, basic
|
|
|
|
|
|
$
|
0.13
|
|
|
|
|
|
|
$
|
(0.50
|
)
|
Pro forma earnings (loss) per share, diluted
|
|
|
|
|
|
$
|
0.13
|
|
|
|
|
|
|
$
|
(0.50
|
)
|
Pro forma weighted average shares, basic
|
|
|
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
86,141,291
|
|
Pro forma weighted average shares, diluted
|
|
|
|
|
|
|
86,158,791
|
|
|
|
|
|
|
|
86,141,291
|
|
42
|
|
|
|
|
|
|
|
|
|
|
As of September 30,
|
|
|
As of September 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
59.9
|
|
|
$
|
30.5
|
|
Working capital
|
|
|
73.6
|
|
|
|
10.7
|
|
Total assets
|
|
|
1,925.5
|
|
|
|
1,868.4
|
|
Total debt, including current portion
|
|
|
500.6
|
|
|
|
500.8
|
|
Minority interest in subsidiaries
|
|
|
10.6
|
|
|
|
10.6
|
|
Stockholders equity
|
|
|
569.9
|
|
|
|
432.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated()
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
20.6
|
|
|
$
|
10.5
|
|
|
$
|
61.3
|
|
|
$
|
42.7
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(3)
|
|
|
40.2
|
|
|
|
(43.0
|
)
|
|
|
111.4
|
|
|
|
16.0
|
|
Cash flows provided by operating activities
|
|
|
81.5
|
|
|
|
5.0
|
|
|
|
104.8
|
|
|
|
165.7
|
|
Cash flows (used in) investing activities
|
|
|
(17.8
|
)
|
|
|
(25.6
|
)
|
|
|
(67.4
|
)
|
|
|
(239.7
|
)
|
Cash flows provided by (used in) financing activities
|
|
|
(24.4
|
)
|
|
|
24.9
|
|
|
|
(8.0
|
)
|
|
|
59.4
|
|
Capital expenditures for property, plant and equipment
|
|
|
17.8
|
|
|
|
25.6
|
|
|
|
67.4
|
|
|
|
239.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Three Months Ended September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (barrels per day)(4)
|
|
|
132,210
|
|
|
|
58,382
|
|
|
|
125,811
|
|
|
|
71,454
|
|
Crude oil throughput (barrels per day)(4)
|
|
|
114,678
|
|
|
|
52,497
|
|
|
|
108,611
|
|
|
|
64,829
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)(5)
|
|
|
110.3
|
|
|
|
75.9
|
|
|
|
273.5
|
|
|
|
244.9
|
|
UAN (tons in thousands)
|
|
|
172.8
|
|
|
|
128.0
|
|
|
|
462.0
|
|
|
|
432.6
|
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
43
|
|
|
(1) |
|
Depreciation and amortization is comprised of the following
components as excluded from cost of product sold, direct
operating expenses and selling, general administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Depreciation and amortization excluded from cost of product sold
|
|
$
|
0.6
|
|
|
$
|
0.6
|
|
|
$
|
1.8
|
|
|
$
|
1.8
|
|
Depreciation and amortization excluded from direct operating
expenses
|
|
|
19.5
|
|
|
|
9.6
|
|
|
|
58.3
|
|
|
|
40.2
|
|
Depreciation and amortization excluded from selling, general and
administrative expenses
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
1.2
|
|
|
|
0.7
|
|
Depreciation included in net costs associated with the flood
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
20.6
|
|
|
$
|
18.1
|
|
|
$
|
61.3
|
|
|
$
|
50.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2) |
|
The following are certain charges and costs incurred in
each of the relevant periods that are meaningful to
understanding our net income (loss) and in evaluating our
performance: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Funded letter of credit expense and interest rate swap not
included in interest expense(a)
|
|
$
|
2.3
|
|
|
$
|
0.7
|
|
|
$
|
5.6
|
|
|
$
|
0.9
|
|
Major scheduled turnaround expense(b)
|
|
|
0.1
|
|
|
|
|
|
|
|
0.1
|
|
|
|
76.8
|
|
Unrealized net (gain) loss from Cash Flow Swap
|
|
|
(98.9
|
)
|
|
|
(90.2
|
)
|
|
|
(69.1
|
)
|
|
|
98.3
|
|
|
|
|
(a) |
|
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. |
|
(b) |
|
Represents expenses associated with a major scheduled turnaround
for the fertilizer facility in October 2008 and for the refinery
in 2007. |
|
|
|
(3) |
|
Net income (loss) adjusted for unrealized loss (net) from Cash
Flow Swap results from adjusting for the derivative transaction
that was executed in conjunction with the acquisition of
Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC
(CALLC) on June 24, 2005. On June 16, 2005, CALLC
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 CALLC to CRLLC on
June 24, 2005. The derivative took the form of three NYMEX
swap agreements whereby if absolute (i.e., in dollar terms, not
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 57% and 14% of crude oil capacity for the periods
October 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 executed crude oil capacity, for the period
from April 1, 2008 through December 31, 2008 and
terminate the Cash Flow Swap in 2009 and 2010, at which time the
unrealized loss would become a fixed obligation. |
|
|
|
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 are accounted for as a
liability on our balance sheet. As the absolute crack spreads |
44
|
|
|
|
|
increase we are required to record an increase in this liability
account with a corresponding expense entry to be made to our
Statements 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
U.S. 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 gain or 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) (in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated()
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
Net income (loss) adjusted for unrealized loss from Cash Flow
Swap
|
|
$
|
40.2
|
|
|
$
|
(43.0
|
)
|
|
$
|
111.4
|
|
|
$
|
16.0
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from Cash Flow Swap, net of taxes
|
|
|
59.5
|
|
|
|
54.2
|
|
|
|
41.5
|
|
|
|
(59.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
99.7
|
|
|
$
|
11.2
|
|
|
$
|
152.9
|
|
|
$
|
(43.1
|
)
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
|
(4) |
|
Barrels per day are 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. |
|
(5) |
|
The tons produced for ammonia represent the total ammonia
produced including ammonia produced that was upgraded into UAN.
The net tons produced that could be sold were 39.0, 23.9, 83.3
and 68.8 for the three months ended September 30, 2008 and
2007 and the nine months ended September 30, 2008 and 2007,
respectively. |
45
The tables below provide an overview of the petroleum
business results of operations, relevant market indicators
and its key operating statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated()
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Petroleum Business Financial Results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
1,510.3
|
|
|
$
|
545.9
|
|
|
$
|
4,137.9
|
|
|
$
|
1,707.3
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
1,437.7
|
|
|
|
450.2
|
|
|
|
3,758.4
|
|
|
|
1,319.2
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
37.1
|
|
|
|
29.5
|
|
|
|
120.1
|
|
|
|
170.7
|
|
Net costs associated with flood
|
|
|
(1.0
|
)
|
|
|
28.6
|
|
|
|
7.9
|
|
|
|
30.6
|
|
Depreciation and amortization
|
|
|
15.6
|
|
|
|
6.6
|
|
|
|
46.8
|
|
|
|
29.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
20.9
|
|
|
$
|
31.0
|
|
|
$
|
204.7
|
|
|
$
|
157.1
|
|
Plus direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
37.1
|
|
|
|
29.5
|
|
|
|
120.1
|
|
|
|
170.7
|
|
Plus net costs associated with flood
|
|
|
(1.0
|
)
|
|
|
28.6
|
|
|
|
7.9
|
|
|
|
30.6
|
|
Plus depreciation and amortization
|
|
|
15.6
|
|
|
|
6.6
|
|
|
|
46.8
|
|
|
|
29.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin(1)
|
|
$
|
72.6
|
|
|
$
|
95.7
|
|
|
$
|
379.5
|
|
|
$
|
388.1
|
|
Refining margin per crude oil throughput barrel(1)
|
|
$
|
6.88
|
|
|
$
|
19.81
|
|
|
$
|
12.75
|
|
|
$
|
21.93
|
|
Gross profit per crude oil throughput barrel
|
|
$
|
1.98
|
|
|
$
|
6.42
|
|
|
$
|
6.88
|
|
|
$
|
8.88
|
|
Direct operating expenses (exclusive of depreciation and
amortization) per crude oil throughput barrel
|
|
$
|
3.52
|
|
|
$
|
6.11
|
|
|
$
|
4.04
|
|
|
$
|
9.64
|
|
Operating income
|
|
|
20.2
|
|
|
|
19.4
|
|
|
|
185.7
|
|
|
|
122.3
|
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
|
(1) |
|
Refining margin is a measurement calculated as the difference
between net sales and cost of product 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 product sold that we are able to sell
refined products. Each of the components used in this
calculation (net sales and cost of product sold (exclusive of
depreciation and amortization)) is 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 usefulness as a comparative
measure. In order to derive the refining margin per crude oil
throughput barrel, we utilize the total dollar figures for
refining margin as derived above and divide by the applicable
number of crude oil throughput barrels for the period. |
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
As Restated()
|
|
|
|
|
|
As Restated
|
|
|
|
(Dollars per barrel)
|
|
|
(Dollars per barrel)
|
|
|
Market Indicators:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) crude oil
|
|
$
|
118.22
|
|
|
$
|
75.15
|
|
|
$
|
113.52
|
|
|
$
|
66.19
|
|
NYMEX 2-1-1 Crack Spread
|
|
|
13.33
|
|
|
|
12.12
|
|
|
|
14.09
|
|
|
|
15.45
|
|
Crude Oil Differentials:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI less WTS (sour)
|
|
|
2.31
|
|
|
|
5.16
|
|
|
|
3.84
|
|
|
|
4.63
|
|
WTI less WCS (heavy sour)
|
|
|
18.69
|
|
|
|
25.80
|
|
|
|
20.58
|
|
|
|
19.54
|
|
WTI less Dated Brent (foreign)
|
|
|
3.13
|
|
|
|
0.40
|
|
|
|
2.41
|
|
|
|
(0.93
|
)
|
PADD II Group 3 Basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
2.62
|
|
|
|
8.78
|
|
|
|
(0.81
|
)
|
|
|
4.68
|
|
Heating Oil
|
|
|
4.68
|
|
|
|
10.14
|
|
|
|
4.17
|
|
|
|
9.77
|
|
PADD II Group 3 Crack:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
8.52
|
|
|
|
20.57
|
|
|
|
6.47
|
|
|
|
22.48
|
|
Heating Oil
|
|
|
25.43
|
|
|
|
22.58
|
|
|
|
25.07
|
|
|
|
22.86
|
|
Company Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per gallon sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
3.06
|
|
|
|
2.28
|
|
|
|
2.87
|
|
|
|
2.14
|
|
Distillate
|
|
|
3.45
|
|
|
|
2.35
|
|
|
|
3.33
|
|
|
|
2.12
|
|
|
|
|
|
|
See note 2 to condensed consolidated financial statements. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
per Day
|
|
|
%
|
|
|
Volumetric Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gasoline
|
|
|
59,864
|
|
|
|
45.3
|
|
|
|
25,971
|
|
|
|
44.4
|
|
|
|
57,195
|
|
|
|
45.5
|
|
|
|
29,949
|
|
|
|
41.9
|
|
Total distillate
|
|
|
51,744
|
|
|
|
39.1
|
|
|
|
23,448
|
|
|
|
40.2
|
|
|
|
49,509
|
|
|
|
39.3
|
|
|
|
29,511
|
|
|
|
41.3
|
|
Total other
|
|
|
20,602
|
|
|
|
15.6
|
|
|
|
8,963
|
|
|
|
15.4
|
|
|
|
19,107
|
|
|
|
15.2
|
|
|
|
11,994
|
|
|
|
16.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total all production
|
|
|
132,210
|
|
|
|
100.0
|
|
|
|
58,382
|
|
|
|
100.0
|
|
|
|
125,811
|
|
|
|
100.0
|
|
|
|
71,454
|
|
|
|
100.0
|
|
Crude oil throughput
|
|
|
114,678
|
|
|
|
90.7
|
|
|
|
52,497
|
|
|
|
93.9
|
|
|
|
108,611
|
|
|
|
90.5
|
|
|
|
64,829
|
|
|
|
94.7
|
|
All other inputs
|
|
|
11,755
|
|
|
|
9.3
|
|
|
|
3,403
|
|
|
|
6.1
|
|
|
|
11,453
|
|
|
|
9.5
|
|
|
|
3,643
|
|
|
|
5.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks
|
|
|
126,433
|
|
|
|
100.0
|
|
|
|
55,900
|
|
|
|
100.0
|
|
|
|
120,064
|
|
|
|
100.0
|
|
|
|
68,472
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Crude oil throughput by crude oil type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet
|
|
|
8,484,339
|
|
|
|
80.4
|
|
|
|
2,835,032
|
|
|
|
58.7
|
|
|
|
21,834,595
|
|
|
|
73.4
|
|
|
|
11,203,099
|
|
|
|
63.3
|
|
Light/medium sour
|
|
|
1,035,395
|
|
|
|
9.8
|
|
|
|
1,168,786
|
|
|
|
24.2
|
|
|
|
4,627,478
|
|
|
|
15.5
|
|
|
|
5,256,430
|
|
|
|
29.7
|
|
Heavy sour
|
|
|
1,030,603
|
|
|
|
9.8
|
|
|
|
825,878
|
|
|
|
17.1
|
|
|
|
3,297,265
|
|
|
|
11.1
|
|
|
|
1,238,889
|
|
|
|
7.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil throughput
|
|
|
10,550,337
|
|
|
|
100.0
|
|
|
|
4,829,696
|
|
|
|
100.0
|
|
|
|
29,759,338
|
|
|
|
100.0
|
|
|
|
17,698,418
|
|
|
|
100.0
|
|
47
The tables below provide an overview of the nitrogen fertilizer
business results of operations, relevant market indicators
and key operating statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Nitrogen Fertilizer Business Financial Results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
74.2
|
|
|
$
|
40.8
|
|
|
$
|
195.6
|
|
|
$
|
115.1
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
6.2
|
|
|
|
3.7
|
|
|
|
21.9
|
|
|
|
9.9
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
19.4
|
|
|
|
14.9
|
|
|
|
59.4
|
|
|
|
48.1
|
|
Net cost associated with flood
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
2.0
|
|
Depreciation and amortization
|
|
|
4.5
|
|
|
|
3.6
|
|
|
|
13.4
|
|
|
|
12.4
|
|
Operating income
|
|
|
46.5
|
|
|
|
13.8
|
|
|
|
95.6
|
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Market Indicators (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (dollars per MMBtu)
|
|
$
|
8.99
|
|
|
$
|
6.24
|
|
|
$
|
9.75
|
|
|
$
|
7.02
|
|
Ammonia Southern Plains (dollars per ton)
|
|
|
936
|
|
|
|
388
|
|
|
|
735
|
|
|
|
393
|
|
UAN Corn Belt (dollars per ton)
|
|
|
506
|
|
|
|
298
|
|
|
|
429
|
|
|
|
276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Company Operating Statistics (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (thousand tons):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia(1)
|
|
|
110.3
|
|
|
|
75.9
|
|
|
|
273.5
|
|
|
|
244.9
|
|
UAN
|
|
|
172.8
|
|
|
|
128.0
|
|
|
|
462.0
|
|
|
|
432.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
283.1
|
|
|
|
203.9
|
|
|
|
735.5
|
|
|
|
677.5
|
|
Sales (thousand tons)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
21.9
|
|
|
|
24.7
|
|
|
|
65.2
|
|
|
|
58.8
|
|
UAN
|
|
|
165.4
|
|
|
|
120.6
|
|
|
|
462.0
|
|
|
|
414.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
187.3
|
|
|
|
145.3
|
|
|
|
527.2
|
|
|
|
473.0
|
|
Product pricing (plant gate) (dollars per ton)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
$
|
685
|
|
|
$
|
363
|
|
|
$
|
568
|
|
|
$
|
358
|
|
UAN
|
|
|
324
|
|
|
|
234
|
|
|
|
296
|
|
|
|
203
|
|
On-stream factor(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
98.5
|
%
|
|
|
81.3
|
%
|
|
|
91.1
|
%
|
|
|
87.4
|
%
|
Ammonia
|
|
|
97.8
|
%
|
|
|
80.4
|
%
|
|
|
89.6
|
%
|
|
|
84.6
|
%
|
UAN
|
|
|
94.8
|
%
|
|
|
71.8
|
%
|
|
|
86.4
|
%
|
|
|
78.5
|
%
|
Reconciliation to net sales (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Freight in revenue
|
|
$
|
5,562
|
|
|
$
|
3,581
|
|
|
$
|
13,634
|
|
|
$
|
10,011
|
|
Hydrogen revenue
|
|
|
40
|
|
|
|
|
|
|
|
7,932
|
|
|
|
|
|
Sales net plant gate
|
|
|
68,553
|
|
|
|
37,175
|
|
|
|
173,991
|
|
|
|
105,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net sales
|
|
|
74,155
|
|
|
|
40,756
|
|
|
|
195,557
|
|
|
|
115,091
|
|
48
|
|
|
(1) |
|
The tons produced for ammonia represent the total ammonia
produced including ammonia produced that was upgraded into UAN.
The net tons produced that could be sold were 39.0, 23.9, 83.3
and 68.8 for the three months ended September 30, 2008 and
2007 and the nine months ended September 30, 2008 and 2007,
respectively. |
|
(2) |
|
Plant gate sales per ton represents net sales less freight and
hydrogen revenue divided by product sales volume in tons in the
reporting period. Plant gate pricing per ton is shown in order
to provide a pricing measure that is comparable across the
fertilizer industry. |
|
(3) |
|
On-stream factor is the total number of hours operated divided
by the total number of hours in the reporting period. |
Three
Months Ended September 30, 2008 Compared to the Three
Months Ended September 30, 2007
Consolidated
Results of Operations
Net Sales. Consolidated net sales were
$1,580.9 million for the three months ended
September 30, 2008 compared to $586.0 million for the
three months ended September 30, 2007. The increase of
$994.9 million for the three months ended
September 30, 2008 as compared to the three months ended
September 30, 2007 was primarily due to an increase in
petroleum net sales of $964.4 million that resulted from
higher product prices ($203.1 million) and higher sales
volumes ($761.3 million) primarily resulting from the
refinery turnaround which began in February 2007 and was
completed in April 2007 and refinery downtime resulting from the
flood. In addition, nitrogen fertilizer net sales increased
$33.4 million for the three months ended September 30,
2008 as compared to the three months ended September 30,
2007 primarily due to higher plant gate prices
($19.6 million) and an increase in overall sales volume
($13.8 million). These results reflect, in part, refinery
hardware expansions completed in 2007, particularly the CCR
addition and coker expansion. The CCR produces significantly
more hydrogen than the unit it replaces. As a result, our
refinery purchases very little hydrogen from the fertilizer
plant, allowing the fertilizer plant to use that hydrogen to
produce ammonia.
Cost of Product Sold Exclusive of Depreciation and
Amortization. Consolidated cost of product sold
(exclusive of depreciation and amortization) was
$1,440.3 million for the three months ended
September 30, 2008 as compared to $453.2 million for
the three months ended September, 2007. The increase of
$987.1 million for the three months ended
September 30, 2008 as compared to the three months ended
September 30, 2007 was attributable to an increase in crude
throughput over the comparable period as the benefits of the
refinery expansion positively impacted crude oil throughput, and
the downtime resulting from the flood had the impact of lowering
refined fuel production volume in the quarter ended
September 30, 2007. Additionally, higher crude oil prices
were a significant contributor to the increase.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Consolidated direct operating
expenses (exclusive of depreciation and amortization) were
$56.6 million for the three months ended September 30,
2008 as compared to $44.5 million for the three months
ended September 30, 2007. This increase of
$12.1 million for the three months ended September 30,
2008 as compared to the three months ended September 30,
2007 was primarily due to an increase in petroleum direct
operating expenses of $7.6 million primarily the result of
increases in expenses associated with utilities and energy,
production chemicals, labor, insurance rent and operating
materials partially offset by deceases in expenses associated
with repairs and maintenance, taxes and outside services.
Nitrogen fertilizer accounted for $4.5 million of the
increase in direct operating expenses over the comparable period
primarily as a result of increases in expenses associated with
property taxes, outside services, utilities, catalyst,
refractory, insurance, turnaround and slag disposal partially
offset by deceases in expenses associated with repairs and
maintenance, royalties and other expenses. The nitrogen
fertilizer facility was subject to a property tax abatement that
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
($7.8) million for the three months ended
September 30, 2008 as compared to $14.0 million for
the three months ended September 30, 2007. This variance
was primarily the result of decreases in share-based
compensation ($26.3 million) and bank charges
($0.2 million) which were partially offset
49
by increases in expenses related to administrative labor
($1.5 million), outside services ($1.2 million), other
selling, general and administrative costs ($0.9 million),
office costs ($0.4 million) and insurance
($0.3 million).
Net Costs Associated with Flood. Consolidated
net costs associated with flood for the three months ended
September 30, 2008 approximated ($0.8) million as
compared to $32.2 for the three months ended September 30,
2007. The $0.8 million of cost recoveries in net costs
associated with flood for the three months ended
September 30, 2008 resulted primarily from the collection
of $15.0 million of insurance proceeds related to our
environmental claim in excess of the environmental insurance
receivable booked as recoverable for accounting purposes.
Depreciation and Amortization. Consolidated
depreciation and amortization was $20.6 million for the
three months ended September 30, 2008 as compared to
$10.5 million for the three months ended September 30,
2007. The increase in depreciation and amortization for the
three months ended September 30, 2008 as compared to the
three months ended September 30, 2007 was primarily the
result of the completion of a significant capital project in the
Petroleum business in February 2008.
Operating Income. Consolidated operating
income was $72.0 million for the three months ended
September 30, 2008 as compared to operating income of
$31.6 million for the three months ended September 30,
2007. For the three months ended September 30, 2008 as
compared to the three months ended September 30, 2007,
petroleum operating income increased $0.8 million and
nitrogen fertilizer operating income increased by
$32.7 million.
Interest Expense and Other Financing
Costs. Consolidated interest expense for the
three months ended September 30, 2008 was $9.3 million
as compared to interest expense of $18.3 million for the
three months ended September 30, 2007. This $9.0 decrease
for the three months ended September 30, 2008 as compared
to the three months ended September 30, 2007 primarily
resulted from an overall decrease in the index rates (primarily
LIBOR) and a decrease in average borrowings outstanding during
the comparable periods. Additionally, consolidated interest
expense during the three months ended September 30, 2008
benefited from decreases in the applicable margins under our
Credit Facility as compared to the applicable margins in effect
for the three months ended September 30, 2007. See
Liquidity and Capital Resources
Debt.
Interest Income. Interest income was
$0.3 million for the three months ended September 30,
2008 as compared to $0.2 million for the three months ended
September 30, 2007.
Gain (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 September 30, 2008, we incurred
$76.7 million in gains on derivatives compared to a
$40.5 million gain on derivatives for the three months
ended September 30, 2007. This significant increase in
gains on derivatives, net for the three months ended
September 30, 2008 as compared to the three months ended
September 30, 2007 was primarily attributable to the
realized losses and unrealized gains on our Cash Flow Swap.
Realized losses on the Cash Flow Swap for the three months ended
September 30, 2008 and the three months ended
September 30, 2007 were $33.8 million and
$45.4 million, respectively. The decrease in realized
losses over the comparable periods was primarily the result of
lower average crack spreads for the three months ended
September 30, 2008 as compared to the three months ended
September 30, 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 forward NYMEX crack
spread that is the basis for the Cash Flow Swap. In addition to
the mark-to-market value of the Cash Flow Swap, the outstanding
term of the Cash Flow Swap at the end of each period also
affects the impact that the changes in the forward NYMEX crack
spread may have on the unrealized gain or loss. As of
September 30, 2008, the Cash Flow Swap had a remaining term
of approximately one year and nine months whereas as of
September 30, 2007, the remaining term was approximately
two years and nine months. As a result of the shorter remaining
term as of September 30, 2008, a similar change in the
forward NYMEX crack spread will have a smaller impact on the
unrealized gain or loss. Unrealized gains on our Cash Flow Swap
for the three months ended September 30, 2008 and the three
months ended September 30, 2007 were $98.9 million and
$90.2 million, respectively.
Provision for Income Taxes. Income tax expense
for the three months ended September 30, 2008 was
$40.4 million, or 28.9% of income before income taxes, as
compared to $42.7 million, or 79.2%, for the three months
ended September 30, 2007. The annualized effective rate for
2007, which was applied to loss before income
50
taxes for the three months ended September 30, 2007, is
higher than the comparable annualized effective rate for 2008,
primarily due to the correlation between the amount of credits
which were projected to be generated in 2007 from the production
of ultra low sulfur diesel fuel and the increased level of
projected loss before income taxes for 2007. On an annualized
basis, we expect to recognize net federal and state income tax
expense at the statutory rate of approximately 39.9% on pre-tax
earnings adjusted for permanent non-deductible or non-taxable
items and to benefit from gross income tax credits of
approximately $60.4 million.
Minority Interest in (income) loss of
Subsidiaries. Minority interest in loss of
subsidiaries for the three months ended September 30, 2007
was $0.1 million. 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.
Net Income (Loss). For the three months ended
September 30, 2008, net income increased to
$99.7 million as compared to net income of
$11.2 million for the three months ended September 30,
2007.
Petroleum
Results of Operations for the Three Months Ended
September 30, 2008
Net Sales. Petroleum net sales were
$1,510.3 million for the three months ended
September 30, 2008 compared to $545.9 million for the
three months ended September 30, 2007. The increase of
$964.4 million during the three months ended
September 30, 2008 as compared to the three months ended
September 30, 2007 was primarily the result of higher
product prices ($203.1 million) and higher sales volumes
($761.3 million). Overall sales volumes of refined fuels
for the three months ended September 30, 2008 increased
114% as compared to the three months ended September 30,
2007. The increased sales volume primarily resulted from a
significant increase in refined fuel production volumes over the
comparable period due to refinery downtime in the 2007 period
resulting from the flood. In the third quarter of 2007, crude
oil throughput averaged 52,497 barrels per day compared to
114,678 barrels per day for the third quarter of 2008. Our
average sales price per gallon for the three months ended
September 30, 2008 for gasoline of $3.06 and distillate of
$3.45 increased by 34% and 47%, respectively, as compared to the
three months ended September 30, 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 $1,437.7 million for the three months
ended September 30, 2008 compared to $450.2 million
for the three months ended September 30, 2007. The increase
of $987.5 million during the three months ended
September 30, 2008 as compared to the three months ended
September 30, 2007 was primarily attributable to a 118%
increase in crude oil throughput primarily due to refinery
downtime in the comparable 2007 period resulting from the flood.
In addition to increased crude oil throughput, 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 September 30, 2008 was
$117.81 compared to $70.93 for the comparable period of 2007, an
increase of 66%. Sales volume of refined fuels increased 114%
for the three months ended September 30, 2008 as compared
to the three months ended September 30, 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 a
favorable FIFO impact when crude oil prices increase and an
unfavorable FIFO impact when crude oil prices decrease. For the
three months ended September 30, 2008, we had an
unfavorable FIFO impact of $59.3 million compared to a
favorable FIFO impact of $22.6 million for the comparable
period of 2007.
Refining margin per barrel of crude throughput decreased from
$19.81 for the three months ended September 30, 2007 to
$6.88 for the three months ended September 30, 2008. Gross
profit per barrel decreased to $1.98 in the third quarter of
2008, as compared to $6.42 per barrel in the equivalent period
in 2007. The primary contributors to the negative variance in
refining margin per barrel of crude throughput were unfavorable
regional differences between gasoline and distillate prices in
our primary marketing region and those of the NYMEX. The average
gasoline basis for the three months ended September 30,
2008 decreased by $6.16 per barrel to $2.62 per barrel compared
to basis of $8.78 per barrel in the comparable period of 2007.
The average distillate basis decreased by $5.46 per barrel to
$4.68 per barrel compared to $10.14 per barrel in the comparable
period of 2007. FIFO inventory losses of $59.3 million for
the three months ended September 30, 2008 as compared to
FIFO inventory gains of $22.6 million for the comparable
51
period of 2007 also contributed significantly to the negative
variance in refining margin per barrel of crude throughput over
the comparable periods. Partially offsetting the negative
effects of refined fuels basis and the impact of FIFO inventory
changes was a 10% increase in the NYMEX 2-1-1 crack spread
($1.21 per barrel) over the comparable periods.
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 $37.1 million for the three months
ended September 30, 2008 compared to direct operating
expenses of $29.5 million for the three months ended
September 30, 2007. The increase of $7.6 million for
the three months ended September 30, 2008 compared to the
three months ended September 30, 2007 was the result of
increases in expenses associated with utilities and energy
($4.7 million), production chemicals ($2.8 million),
labor ($1.7 million), insurance ($0.9 million), rent
($0.4 million) and operating materials ($0.4 million).
These increases in direct operating expenses were partially
offset by decreases in expenses associated with repairs and
maintenance ($2.5 million), taxes ($1.1 million) and
outside services ($0.8 million). On a per barrel of crude
throughput basis, direct operating expenses per barrel of crude
oil throughput for the three months ended September 30,
2008 decreased to $3.52 per barrel as compared to $6.11 per
barrel for the three months ended September 30, 2007.
Net Costs Associated with Flood. Petroleum net
costs associated with flood for the three months ended
September 30, 2008 recorded cost recoveries of approximated
$1.0 million as compared to expense of approximately
$28.6 million for the three months ended September 30,
2007. This cost recovery resulted primarily from the collection
of $15.0 million of insurance proceeds related to our
environmental claim in excess of the environmental insurance
receivable booked as recoverable for accounting purposes.
Depreciation and Amortization. Petroleum
depreciation and amortization was $15.6 million for the
three months ended September 30, 2008 as compared to
$6.6 million for the three months ended September 30,
2007. This increase in petroleum depreciation and amortization
for the three months ended September 30, 2008 as compared
to the three months ended September 30, 2007 was primarily
the result of a large capital project completed in February 2008.
Operating Income. Petroleum operating income
was $20.2 million for the three months ended
September 30, 2008 as compared to operating income of
$19.4 million for the three months ended September 30,
2007. This increase of $0.8 million from the three months
ended September 30, 2008 as compared to the three months
ended September 30, 2007 was primarily the result of a
significant decrease in refined fuels basis and a
$81.9 million negative variance in FIFO inventory valuation
over the comparable periods. Additionally, increases in expenses
associated with utilities and energy ($4.7 million),
production chemicals ($2.8 million), labor
($1.7 million), insurance ($0.9 million), rent
($0.4 million) and operating materials ($0.4 million)
also negatively impacted operating income over the comparable
periods. These increases in direct operating expenses were
partially offset by decreases in expenses associated with
repairs and maintenance ($2.5 million), taxes
($1.1 million) and outside services ($0.8 million).
Nitrogen
Fertilizer Results of Operations for the Three Months Ended
September 30, 2008
Net Sales. Nitrogen fertilizer net sales were
$74.2 million for the three months ended September 30,
2008 compared to $40.8 million for the three months ended
September 30, 2007. The increase of $33.4 million for
the three months ended September 30, 2008 as compared to
the three months ended September 30, 2007 was the result of
higher plant gate prices ($19.6 million), coupled with an
increase in overall sales volumes ($13.8 million).
In regard to product sales volumes for the three months ended
September 30, 2008, our nitrogen fertilizer operations
experienced a decrease of 11% in ammonia sales unit volumes
(2,719 tons) and an increase of 37% in UAN sales unit volumes
(44,755 tons). On-stream factors (total number of hours operated
divided by total hours in the reporting period) for all units
gasification, ammonia and UAN plant were significantly greater
than on-stream factors for the comparable period. During the
three months ended September 30, 2007, all three primary
nitrogen fertilizer units experienced eighteen days of downtime
associated with the flood. In addition, the UAN plant also
experienced unscheduled downtime for repairs and maintenance. It
is typical to experience brief outages in complex
52
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 September 30, 2008 for ammonia and
UAN were greater than plant gate prices for the comparable
period of 2007 by 89% and 38%, 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
historically low ending stocks of global grains and a surge in
prices for corn, wheat and soybeans, the primary 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 September 30, 2008 was $6.2 million
compared to $3.7 million for the three months ended
September 30, 2007. The increase of $2.5 million for
the three months ended September 30, 2008 as compared to
the three months ended September 30, 2007 was primarily the
result of a change in intercompany accounting for hydrogen
reimbursement. For the three months ended September 30,
2007, hydrogen reimbursement was included in cost of product
sold (exclusive of depreciation and amortization). For the three
months ended September 30, 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. This transfer of hydrogen has
virtually been eliminated with the completion and operation of
the CCR at the refinery.
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
September 30, 2008 were $19.4 million as compared to
$14.9 million for the three months ended September 30,
2007. The increase of $4.5 million for the three months
ended September 30, 2008 as compared to the three months
ended September 30, 2007 was primarily the result of
increases in expenses associated with property taxes
($2.5 million), outside services ($1.3 million),
utilities ($0.9 million), catalyst ($0.7 million),
refractory ($0.3 million), insurance ($0.2 million),
turnaround ($0.1 million) and slag disposal
($0.1 million). These increases in direct operating
expenses were partially offset by decreases in expenses
associated with repairs and maintenance ($1.1 million) and
royalties and other ($0.8 million).
Depreciation and Amortization. Nitrogen
fertilizer depreciation and amortization increased to
$4.5 million for the three months ended September 30,
2008 as compared to $3.6 million for the three months ended
September 30, 2007.
Net Costs Associated with Flood. Nitrogen net
costs associated with flood for the three months ended
September 30, 2007 was approximately $1.9 million.
There were no costs associated with the flood for the three
months ended September 30, 2008.
Operating Income. Nitrogen fertilizer
operating income was $46.5 million for the three months
ended September 30, 2008 as compared to operating income of
$13.8 million for the three months ended September 30,
2007. This increase of $32.7 million for the three months
ended September 30, 2008 as compared to the three months
ended September 30, 2007 was primarily the result of
increased fertilizer prices and sales volumes over the
53
comparable periods. Mitigating the increased fertilizer prices
and sales volumes over the comparable periods were increases in
direct operating expenses associated with property taxes
($2.5 million), outside services ($1.3 million),
utilities ($0.9 million), catalyst ($0.7 million),
refractory ($0.3 million), insurance ($0.2 million),
turnaround ($0.1 million) and slag disposal
($0.1 million). These increases in direct operating
expenses were partially offset by decreases in expenses
associated with repairs and maintenance ($1.1 million) and
royalties and other ($0.8 million).
Nine
Months Ended September 30, 2008 Compared to the Nine Months
Ended September 30, 2007
Consolidated
Results of Operations
Net Sales. Consolidated net sales were
$4,316.4 million for the nine months ended
September 30, 2008 compared to $1,819.9 million for
the nine months ended September 30, 2007. The increase of
$2,496.5 million for the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 was primarily due to an increase in
petroleum net sales of $2,430.6 million that resulted from
higher sales volumes ($1,623.1 million), coupled with
higher product prices ($807.5 million). In addition,
nitrogen fertilizer net sales increased $80.5 million for
the nine months ended September 30, 2008 as compared to the
nine months ended September 30, 2007 due to higher sales
volumes ($19.3 million), higher plant gate prices
($53.3 million) and a change in intercompany accounting for
hydrogen from cost of product sold (exclusive of depreciation
and amortization) to net sales ($7.9 million) over the
comparable periods, which eliminates in consolidation.
Cost of Product Sold Exclusive of Depreciation and
Amortization. Consolidated cost of product sold
(exclusive of depreciation and amortization) was
$3,764.0 million for the nine months ended
September 30, 2008 as compared to $1,326.6 million for
the nine months ended September 30, 2007. The increase of
$2,437.4 million for the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 was primarily due to the refinery
turnaround that began in February 2007 and was completed in
April 2007 and refinery downtime resulting from the flood. In
addition to the impact of the turnaround and the flood, higher
crude oil prices, increased sales volumes and the impact of FIFO
accounting impacted cost of product sold during the comparable
periods. Our average cost per barrel of crude oil for the nine
months ended September 30, 2008 was $110.10, compared to
$60.90 for the comparable period of 2007, an increase of 81%.
Sales volume of refined fuels increased 70% for the nine months
ended September 30, 2008 as compared to the nine months
ended September 30, 2007 principally due to the turnaround
and refinery downtime resulting from the flood.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Consolidated direct operating
expenses (exclusive of depreciation and amortization) were
$179.5 million for the nine months ended September 30,
2008 as compared to $218.8 million for the nine months
ended September 30, 2007. This decrease of
$39.3 million for the nine months ended September 30,
2008 as compared to the nine months ended September 30,
2007 was due to a decrease in petroleum direct operating
expenses of $50.6 million, primarily related to the
refinery turnaround, partially offset by an increase in nitrogen
fertilizer direct operating expenses of $11.3 million.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization. Consolidated
selling, general and administrative expenses were
$20.5 million for the nine months ended September 30,
2008 as compared to $42.1 million for the nine months ended
September 30, 2007. This variance was primarily the result
of decreases in share-based compensation ($41.3 million)
which was partially offset by increases in expenses associated
with outside services ($5.8 million), bad debt reserve
($3.9 million), the write-off of deferred CVR Partners, LP
initial public offering costs ($2.5 million),
administrative labor ($2.3 million), other selling,
general, and administrative expenses ($2.0 million), asset
write-off ($0.9 million), insurance ($0.9 million) and
office costs ($0.6 million).
Net Costs Associated with Flood. Consolidated
net costs associated with the flood for the nine months ended
September 30, 2008 approximated $8.8 million as
compared to $34.3 for the nine months ended September 30,
2007.
Depreciation and Amortization. Consolidated
depreciation and amortization was $61.3 million for the
nine months ended September 30, 2008 as compared to
$42.7 million for the nine months ended September 30,
2007. The increase of $18.6 million for the nine months
ended September 30, 2008 as compared to the nine months
ended
54
September 30, 2007 was primarily the result of the
expansion completed in April 2007 and a significant capital
project completed in February 2008 in the petroleum business.
Operating Income. Consolidated operating
income was $282.3 million for the nine months ended
September 30, 2008 as compared to operating income of
$155.4 million for the nine months ended September 30,
2007. For the nine months ended September 30, 2008 as
compared to the nine months ended September 30, 2007,
petroleum operating income increased by $63.4 million and
nitrogen fertilizer operating income increased by
$60.7 million.
Interest Expense. Consolidated interest
expense for the nine months ended September 30, 2008 was
$30.1 million as compared to interest expense of
$46.0 million for the nine months ended September 30,
2007. This 35% decrease for the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 primarily resulted from an overall
decrease in the index rates (primarily LIBOR) and a decrease in
average borrowings outstanding during the nine months ended
September 30, 2008. Additionally, consolidated interest
expense during the nine months ended September 30, 2008
benefited from decreases in the applicable margins under our
Credit Facility dated December 28, 2006 as compared to the
applicable margin in effect during the nine months ended
September 30, 2007. See Liquidity and
Capital Resources Debt. Partially offsetting
these positive impacts on consolidated interest expense was a
$7.7 million decrease in capitalized interest over the
comparable period due to the decrease of capital projects in
progress during the nine months ended September 30, 2008.
Interest Income. Interest income was
$1.6 million for the nine months ended September 30,
2008 as compared to $0.8 million for the nine months ended
September 30, 2007.
Gain (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 nine
months ended September 30, 2008, we incurred a
$50.5 million net loss on derivatives as compared to a
$251.9 million loss on derivatives for the nine months
ended September 30, 2007. This significant decrease in loss
on derivatives, net for the nine months ended September 30,
2008 as compared to the nine months ended September 30,
2007 was primarily attributable to the realized and unrealized
losses on our Cash Flow Swap. Realized losses on the Cash Flow
Swap for the nine months ended September 30, 2008 and the
nine months ended September 30, 2007 were
$107.7 million and $142.6 million, respectively. The
decrease in realized losses over the comparable periods was
primarily the result of lower average crack spreads for the nine
months ended September 30, 2008 as compared to the nine
months ended September 30, 2007. 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
forward NYMEX crack spread that is the basis for the Cash Flow
Swap. In addition to the mark-to-market value of the Cash Flow
Swap, the outstanding term of the Cash Flow Swap at the end of
each period also affects the impact that the changes in the
forward NYMEX crack spread may have on the unrealized gain or
loss. As of September 30, 2008, the Cash Flow Swap had a
remaining term of approximately one year and nine months whereas
as of September 30, 2007, the remaining term on the Cash
Flow Swap was approximately two years and nine months. As a
result of those shorter remaining term as of June 30, 2008,
a similar change in the forward NYMEX crack spread will have a
smaller impact on the unrealized gain or loss. Unrealized gains
on our Cash Flow Swap for the nine months ended
September 30, 2008 were $69.1 million. In contrast,
the unrealized losses on the Cash Flow Swap for the nine months
ended September 30, 2007 were $98.3 million.
Provision for Income Taxes. Income tax expense
for the nine months ended September 30, 2008 was
approximately $51.3 million, or 25.1% of earnings before
income taxes, as compared to income tax benefit of approximately
$98.2 million, or 69.3%, for the nine months ended
September 30, 2007. The annualized effective tax rate for
2008, which was applied to earnings before income taxes for the
nine month period ended September 30, 2008, is lower than
the comparable annualized effective tax rate for 2007, which was
applied to loss before income taxes for the nine month period
ended September 30, 2007, primarily due to the correlation
between the amount of income tax credits which were projected to
be generated in 2007 in comparison with the projected pre-tax
loss for 2007.
Minority Interest in (income) loss of
Subsidiaries. Minority interest in income of
subsidiaries for the nine months ended September 30, 2007
was $0.2 million. Minority interest in the 2007 period
related to common stock in two of our subsidiaries owned by our
chief executive officer.
55
Net Income (Loss). For the nine months ended
September 30, 2008, net income was $152.9 million as
compared to a net loss of $43.1 million for the nine months
ended September 30, 2007.
Petroleum
Results of Operations for the Nine Months Ended
September 30, 2008
Net Sales. Petroleum net sales were
$4,137.9 million for the nine months ended
September 30, 2008 compared to $1,707.3 million for
the nine months ended September 30, 2007. The increase of
$2,430.6 million from the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 was primarily the result of
significantly higher sales volumes ($1,623.1 million) and
increased product prices ($807.5 million). Overall sales
volumes of refined fuels for the nine months ended
September 30, 2008 increased 70% as compared to the nine
months ended September 30, 2007. The increased sales volume
resulted primary from a significant decrease in refined fuel
production volumes over the nine months ended September 30,
2007 due to the refinery turnaround which began in February 2007
and was completed in April 2007 and refinery downtime resulting
from the flood. Our average sales price per gallon for the nine
months ended September 30, 2008 for gasoline of $2.87 and
distillate of $3.33 increased by 34% and 57%, respectively, as
compared to the nine months ended September 30, 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 and transportation and distribution costs.
Petroleum cost of product sold (exclusive of depreciation and
amortization) was $3,758.4 million for the nine months
ended September 30, 2008 compared to $1,319.2 million
for the nine months ended September 30, 2007. The increase
of $2,439.2 million from the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 was primarily the result of a
significant increase in crude throughput due to the refinery
turnaround which began in February 2007 and was completed in
April 2007 and refinery downtime resulting from the flood. In
addition to the impact of the turnaround, higher crude oil
prices, increased sales volumes and the impact of FIFO
accounting impacted cost of product sold during the comparable
periods. Our average cost per barrel of crude oil for the nine
months ended September 30, 2008 was $110.10, compared to
$60.90 for the comparable period of 2007, an increase of 81%.
Sales volume of refined fuels increased 70% for the nine months
ended September 30, 2008 as compared to the nine months
ended September 30, 2007 principally due to the turnaround
and the downtime resulting from the 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 nine
months ended September 30, 2008, we reported a favorable
FIFO impact of $25.9 million compared to a favorable FIFO
impact of $36.9 million for the comparable period of 2007.
Refining margin per barrel of crude throughput decreased to
$12.75 for the nine months ended September 30, 2008 from
$21.93 for the nine months ended September 30, 2007
primarily due to the unfavorable regional differences between
gasoline and distillate prices in our primary marketing region
(the Coffeyville supply area) and those of the NYMEX. The
average gasoline basis for the nine months ended
September 30, 2008 decreased by $5.49 per barrel to a
negative basis of ($0.81) per barrel compared to $4.68 per
barrel in the comparable period of 2007. The average distillate
basis for the nine months ended September 30, 2008
decreased by $5.60 per barrel to $4.17 per barrel compared to
$9.77 per barrel in the comparable period of 2007. Also
contributing to the reduced refining margin per barrel was the
9% decrease ($1.36 per barrel) in the average NYMEX 2-1-1 crack
spread over the comparable periods.
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 $120.1 million for the nine months
ended September 30, 2008 compared to direct operating
expenses of $170.7 million for the nine months ended
September 30, 2007. The decrease of $50.6 million for
the nine months ended September 30, 2008 compared to the
nine months ended September 30, 2007 was the result of
decreases in expenses associated with the refinery turnaround
($76.8 million) and outside services ($1.8 million).
These decreases in direct operating expenses were partially
offset by increases in expenses associated with energy and
utilities ($11.9 million), production chemicals
($5.3 million), repairs and maintenance
($4.6 million), insurance ($1.7 million),
56
environmental compliance ($1.4 million), direct labor
($0.7 million), rent and lease ($0.5 million),
operating materials ($0.5 million) and property taxes
($0.1 million). On a per barrel of crude throughput basis,
direct operating expenses per barrel of crude throughput for the
nine months ended September 30, 2008 decreased to $4.04 per
barrel as compared to $9.64 per barrel for the nine months ended
September 30, 2007 principally due to refinery turnaround
expenses and the related downtime associated with the turnaround
and its impact on overall production volume and downtime
resulting from the flood.
Net Costs Associated with Flood. Petroleum net
costs associated with the flood for the nine months ended
September 30, 2008 approximated $7.9 million as
compared to $30.6 million for the nine months ended
September 30, 2007.
Depreciation and Amortization. Petroleum
depreciation and amortization was $46.8 million for the
nine months ended September 30, 2008 as compared to
$29.7 million for the nine months ended September 30,
2007. The increase of $17.1 million for the nine months
ended September 30, 2008 compared to the nine months ended
September 30, 2007 was primarily the result of the
completion of the expansion in April 2007 and a significant
capital project completed in February 2008.
Operating Income. Petroleum operating income
was $185.7 million for the nine months ended
September 30, 2008 as compared to operating income of
$122.3 million for the nine months ended September 30,
2007. This increase of $63.4 million from the nine months
ended September 30, 2008 as compared to the nine months
ended September 30, 2007 was primarily the result of the
refinery turnaround which began in February 2007 and was
completed in April 2007 and refinery downtime resulting from the
flood. The turnaround and the flood negatively impacted daily
refinery crude throughput and refined fuels production. In
addition, direct operating expenses decreased substantially
during the nine months ended September 30, 2008 primarily
due to decreases in expenses associated with the refinery
turnaround ($76.8 million) and outside services
($1.8 million). These decreases in direct operating
expenses were partially offset by increases in expenses
associated with energy and utilities ($11.9 million),
production chemicals ($5.3 million), repairs and
maintenance ($4.6 million), insurance ($1.7 million),
environmental compliance ($1.4 million), direct labor
($0.7 million), rent and lease ($0.5 million),
operating materials ($0.5 million) and property taxes
($0.1 million).
Nitrogen
Fertilizer Results of Operations for the Nine Months Ended
September 30, 2008
Net Sales. Nitrogen fertilizer net sales were
$195.6 million for the nine months ended September 30,
2008 compared to $115.1 million for the nine months ended
September 30, 2007. The increase of $80.5 million from
the nine months ended September 30, 2008 as compared to the
nine months ended September 30, 2007 was the result of
higher plant gate prices ($53.3 million), coupled with an
increase in overall sales volumes ($19.3 million) and a
change in intercompany accounting for hydrogen from cost of
product sold (exclusive of depreciation and amortization) to net
sales ($7.9 million) over the comparable periods, which
eliminates in consolidation.
In regard to product sales volumes for the nine months ended
September 30, 2008, our nitrogen operations experienced an
increase of 11% in ammonia sales unit volumes (6,456 tons) and
an increase of 12% in UAN sales unit volumes (47,824 tons).
On-stream factors (total number of hours operated divided by
total hours in the reporting period) for all units,
gasification, ammonia and UAN plant were greater than the
comparable period, primarily due to unscheduled downtime and
nitrogen plant downtime resulting from the flood. 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 six months to
six months. The plant gate price provides a measure that is
consistently comparable period to period. Plant gate prices for
the nine months ended September 30, 2008 for ammonia were
greater than plant gate prices for the comparable period of 2007
by 59%. Similarly, UAN plant gate prices for the nine months
ending September 30, 2008 were greater than the comparable
period of 2007 by 46%. 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 historically low
ending stocks of global grains and a
57
surge in prices for corn, wheat and soybeans, the primary 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, freight and distribution expenses. Cost of product
sold excluding depreciation and amortization for the nine months
ended September 30, 2008 was $21.9 million compared to
$9.9 million for the nine months ended September 30,
2007. The increase of $12.0 million for the nine months
ended September 30, 2008 as compared to the nine months
ended September 30, 2007 was primarily the result of a
change in intercompany accounting for hydrogen reimbursement
($10.6 million) and a $3.1 million increase in freight
expense over the comparable periods. For the nine months ended
September 30, 2007, hydrogen reimbursement was included in
cost of product sold (exclusive of depreciation and
amortization). For the nine months ended September 30,
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. This transfer of hydrogen has virtually been
eliminated with the completion and operation of the CCR at the
refinery.
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 nine months ended
September 30, 2008 were $59.4 million as compared to
$48.1 million for the nine months ended September 30,
2007. The increase of $11.3 million for the nine months
ended September 30, 2008 as compared to the nine months
ended September 30, 2007 was primarily the result of
increases in expenses associated with property taxes
($7.4 million), outside services ($2.2 million),
catalyst ($2.0 million), repairs and maintenance
($0.7 million), slag disposal ($0.4 million),
refractory ($0.3 million), insurance ($0.3 million)
and direct labor ($0.3 million). These increases in direct
operating expenses were partially offset by reductions in
expenses associated with royalties and other
($2.3 million), environmental compliance
($0.2 million), equipment rental ($0.1 million) and
utilities ($0.1 million).
Net Costs Associated with Flood. The nitrogen
fertilizer operations did not record any costs associated with
the flood for the nine months ended September 30, 2008 as
compared to $2.0 million for the nine months ended
September 30, 2007.
Depreciation and Amortization. Nitrogen
fertilizer depreciation and amortization increased to
$13.4 million for the nine months ended September 30,
2008 as compared to $12.4 million for the nine months ended
September 30, 2007.
Operating Income. Nitrogen fertilizer
operating income was $95.6 million for the nine months
ended September 30, 2008 as compared to $34.9 million
for the nine months ended September 30, 2007. This increase
of $60.7 million for the nine months ended
September 30, 2008 as compared to the nine months ended
September 30, 2007 was the result of increased sales
volumes ($27.2 million), coupled with higher plant gate
prices for both UAN and ammonia ($53.3 million). Partially
offsetting the positive effects of sales volumes and higher
plant gate prices were increased direct operating expenses
primarily the result of increases in expenses associated with
property taxes ($7.4 million), outside services
($2.2 million), catalyst ($2.0 million), repairs and
maintenance ($0.7 million), slag disposal
($0.4 million), refractory ($0.3 million), insurance
($0.3 million) and direct labor ($0.3 million). These
increases in direct operating expenses were partially offset by
reductions in expenses associated with royalties and other
($2.3 million), environmental compliance
($0.2 million), equipment rental ($0.1 million) and
utilities ($0.1 million).
58
Liquidity
and Capital Resources
Our primary sources of liquidity currently consist of cash
generated from our operating activities, existing cash and cash
equivalent balances, our existing revolving credit facility and
third party guarantees of obligations under the Cash Flow Swap.
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 September 30, 2008, total outstanding debt under our
credit facility was $485.5 million. There was no balance
outstanding under our revolving credit facility. As of
November 6, 2008, total outstanding debt under our credit
facility was $484.3 million, which was all term debt. As of
September 30, 2008, we had cash, cash equivalents and
short-term investments of $59.9 million and up to
$115.1 million available under our revolving credit
facility. As of November 6, 2008, we had cash, cash
equivalents and short-term investments of $54.3 million and
up to $115.1 million available under our revolving credit
facility. 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 September 30, 2008 was
approximately $264.5 million, and the current portion
included a decrease of $25.8 million from December 31,
2007, resulting in an equal increase 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 Note 10, Flood, Crude Oil
Discharge and Insurance Related Matters. 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 and crude oil discharge. In order to provide immediate and
future liquidity, on August 23, 2007 we deferred payments
of $123.7 million which were due to J. Aron under the terms
of the Cash Flow Swap. We entered into a letter agreement with
J. Aron on July 29, 2008 to defer to December 15, 2008
the payment of $87.5 million of the $123.7 million
plus accrued interest. On August 29, 2008 we paid $36.2 of
the remaining balance to J. Aron, as well as $7.1 million
in accrued interest.
Subsequent to the quarter end, we paid an additional
$15.0 million through use of proceeds received on the
environmental insurance policy. The deferral agreement with J.
Aron was further amended on October 11, 2008 and the
outstanding balance of $72.5 million on that date was
further deferred to July 31, 2009. Additional proceeds of
$9.8 million received under the property insurance policy
subsequent to October 11, 2008 were used to pay down the
principle balance on the deferral amount to $62.7 million
as of November 6, 2008.
We paid J. Aron $33.8 million on October 7, 2008 for
settlement of our realized losses with respect to the Cash Flow
Swap for the quarter ended September 30, 2008.
The crude oil intermediation agreement with J. Aron expires on
December 31, 2008. We are currently negotiating with
multiple parties to enter into a new intermediation agreement to
replace the J. Aron agreement. There can be no assurance that we
will be able to enter into a new agreement on favorable terms,
on a timely basis, or at all.
Our liquidity is significantly effected by the market price of
crude oil. Higher crude oil prices hurt our liquidity and lower
crude oil prices enhance our liquidity. Given the reduction in
crude oil prices in the third quarter of 2008 and thereafter, we
elected to withdraw our convertible notes offering registration
statement from the SEC as we concluded that such offering was no
longer necessary.
We believe that our cash flows from operations, borrowings under
our revolving credit facility, third party guarantees under the
Cash Flow Swap and other capital resources will be sufficient to
satisfy the anticipated cash requirements associated with our
existing operations for at least the next 12 months.
However, our future capital expenditures and other cash
requirements could be higher than we currently expect as a
result of various factors, such as increased crude oil prices.
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.
59
Debt
Credit
Facility
On December 28, 2006, our subsidiary CRLLC entered into a
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 loan 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
loan 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 December 28, 2013. As of September 30, 2008,
we had available $115.1 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
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60
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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
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 CRLLC 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 CRLLC 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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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
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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
September 30, 2008, we were in compliance with our
covenants under the Credit Facility.
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
61
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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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2008
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2007
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2008
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2007
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(Unaudited in millions)
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(Unaudited in millions)
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Consolidated Financial Results
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Net income (loss)
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$
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99.7
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$
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11.2
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$
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152.9
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$
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(43.1
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)
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Plus:
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Depreciation and amortization
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20.6
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18.1
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61.3
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50.3
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Interest expense and other financing costs
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9.3
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18.3
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30.1
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46.0
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Income tax expense (benefit)
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40.4
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42.7
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51.3
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(98.2
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)
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Funded letters of credit expense and interest rate swap not
included in interest expense
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2.3
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0.7
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5.6
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0.9
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Major scheduled turnaround expense
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0.1
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0.1
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76.8
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Unrealized gain (loss) on derivatives
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(100.6
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(86.2
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(68.8
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103.8
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Non-cash compensation expense for equity awards
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(25.6
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4.5
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(36.8
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11.3
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Loss on disposition of fixed assets
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0.1
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1.6
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1.2
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Minority interest
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0.1
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(0.2
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Management fees
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0.5
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1.6
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Unusual or non recurring charges
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3.2
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Property tax increase due to expiration of abatement
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7.4
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7.4
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Adjusted EBITDA
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$
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53.6
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$
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10.0
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$
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207.9
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$
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150.4
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In addition to the financial covenants summarized in the table
above, the Credit Facility restricts the capital expenditures of
CRLLC 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 ended 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.
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.
62
Under the terms of our Credit Facility, our initial public
offering was deemed a Qualified IPO because the
offering generated at least $250 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 are allowed to borrow an additional
$225.0 million under the Credit Facility 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 are 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 ended December 31,
2008, and (4) we are 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 September 30, 2008 and December 31, 2007, funded
long-term debt, including current maturities, totaled
$485.5 million and $489.2 million, respectively, of
tranche D term loans. Other commitments at
September 30, 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
September 30, 2008, the commitment outstanding on the
revolving credit facility was $34.9 million, including no
revolver borrowings, $3.3 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.
Payment
Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, CRLLC 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 fall below a fixed level, J. Aron
agreed to pay the difference to us, and if crack spreads 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. On July 29, 2008, CRLLC entered into a revised
letter agreement with the J. Aron to defer further
$87.5 million of the deferred payment amounts under the
2007 deferral agreements to December 15, 2008. On
August 29, 2008, in accordance with the additional deferral
agreement, we paid $36.2 million to J. Aron, as well as
$7.1 million in accrued interest as of that date resulting
in a remaining balance due of $87.5 million. As of
September 30, 2008, the outstanding balance due was
$87.5 million and the related accrued interest was
$0.5 million. Subsequent to the September 30, 2008
quarter end, we paid an additional $15.0 million received
on the environmental insurance policy. The deferral agreement
with J. Aron was further amended on October 11, 2008 and
the outstanding balance of $72.5 million on that date was
further deferred to July 31, 2009. Additional proceeds of
$9.8 million received under the property insurance policy
subsequent to October 11, 2008, were used to pay down the
principle balance on the deferral amount to $62.7 million
as of November 6, 2008. The following is a summary of the
various deferral agreements with J. Aron since June 2007.
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On June 26, 2007, CRLLC and J. Aron 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, CRLLC 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
September 30, 2007. J. Aron deferred the $43.7 million
payment on the conditions that (a) each of GS
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63
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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, CRLLC 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, CRLLC 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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On July 29, 2008, the Company entered into a revised letter
agreement with J. Aron to defer further $87.5 million of
the deferred payment amounts owed under the 2007 deferral
agreements. The unpaid deferred amounts and all accrued and
unpaid interest were due and payable in full on
December 15, 2008. If the Company incurred aggregate
indebtedness in an aggregate principal amount of at least
$125.0 million by December 15, 2008, the maturity date
would be automatically extended to July 31, 2009 provided
also that there had been no default of the Company in the
performance of its obligations under the revised letter
agreement. GS and Kelso each agreed to guarantee one half of the
deferred payment of $87.5 million. The Company agreed to
repay deferred amounts in an amount equal to the sum of
$36.2 million plus all accrued and unpaid interest
($7.1 million as of August 29, 2008) by no later
than August 31, 2008. On August 29, 2008, pursuant to
the agreement, we paid J. Aron $36.2 million plus
$7.1 million of accrued interest.
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On October 11, 2008, the Company and J. Aron entered into a
revised letter agreement to defer the outstanding balance of
$72.5 million and all accrued and unpaid interest to
July 31, 2009. However, all accrued interest through
December 15, 2008 must be paid on that day. Interest will
accrue on the amounts deferred at the rate of (i) LIBOR
plus 2.75% until December 15, 2008 and (ii) LIBOR plus
5.00%-7.50% (depending on J. Arons cost of capital) from
December 15, 2008 through the date of payment. CRLLC must
make prepayments of $5.0 million for the quarters ending
March 31, 2009 and June 30, 2009 to reduce the
deferred amounts. To the extent that CRLLC or any of its
subsidiaries receives net insurance proceeds related to the July
2007 flood that they are not required to use to prepay
CRLLCs credit agreement or permitted to invest pursuant to
the terms of CRLLCs credit agreement, all net insurance
proceeds will be used to prepay the deferred amounts. GS and
Kelso each agreed to guarantee one half of the deferred payment
obligations.
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Capital
Spending
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 EPA. In anticipation of a
settlement with the EPA to resolve the non-compliance, the
Company planned to spend $28.0 million in capital required
for interim compliance with the ultra low sulfur gasoline
standards in 2008, ahead of the required full compliance date of
January 1, 2011. As a result of continued discussions with
the EPA and its verbal agreement to modify the required average
annual gasoline sulfur standard as a result of the flood,
approximately $11.7 million of the originally planned
capital spending of $28.0 million for the interim period
has been deferred to 2009. Management is also evaluating whether
any other capital spending projects can be deferred to a later
date.
The Nitrogen Fertilizer business has been moving forward with an
approximately $120 million fertilizer plant expansion which
was originally expected to be completed in July 2010. Most
recently the expected completion date was delayed to December
2010. As of September 30, 2008 approximately
$21.6 million was incurred with respect to the fertilizer
plant expansion. Management is currently evaluating whether to
proceed with an expected
64
completion date of December 2010 or to delay any further work on
this project to a later date. Whether management decides to move
forward depends on a number of factors including but not limited
to current credit market conditions, further analysis and review
of the costs of continued rail car shipments of ammonia as well
as the expected premium on UAN sales.
We will continue to evaluate all proposed projects and the
related capital plan and make modifications as deemed
appropriate with the ever-changing market. We currently do not
anticipate any significant modification will be made to the
capital plan unless there is a decision to postpone the
fertilizer plant expansion.
Cash
Flows
The following table sets forth our cash flows for the periods
indicated below (in millions):
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Nine Months Ended
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September 30,
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2008
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2007
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(Unaudited)
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Net cash provided by (used in):
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Operating activities
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$
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104.8
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$
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165.7
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Investing activities
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(67.4
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)
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(239.7
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Financing activities
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(8.0
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59.4
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Net increase (decrease) in cash and cash equivalents
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$
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29.4
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$
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(14.6
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)
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Cash
Flows Provided by Operating Activities
Net cash flows from operating activities for the nine months
ended September 30, 2008 was $104.8 million compared
to cash flows from operating activities for the nine months
ended September 30, 2007 of $165.7 million. The
positive cash flow from operating activities generated over the
nine months ended September 30, 2008 was primarily driven
by net income, partially offset by unfavorable changes in trade
working capital and other 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 income for the
nine months ended September 30, 2008 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
September 30, 2008 (approximately one year and nine
months), the unrealized gains on the Cash Flow Swap
significantly increased our net income over this period. The
impact of the realized losses and unrealized gains on the Cash
Flow Swap is apparent in the $86.1 million decrease in the
payable to swap counterparty. Trade working capital for the nine
months ended September 30, 2008 resulted in a use of cash
of $32.7 million. For the nine months ended
September 30, 2008, accounts receivable increased
$47.5 million, inventory increased by $11.4 million
and accounts payable increased by $26.2 million.
Net cash flows provided by operating activities for the nine
months ended September 30, 2007 was $165.7 million.
The positive cash flow from operating activities during this
period was primarily the result of favorable changes in other
working capital and trade working capital, partially offset by
unfavorable changes in other assets and liabilities. Net loss
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 nine
months ended September 30, 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
September 30, 2007 (approximately two years and nine
months), the realized and unrealized losses on the Cash Flow
Swap significantly increased our net loss over this period. The
impact of these realized and unrealized losses on the Cash Flow
Swap is apparent in the $230.9 million increase in the
payable to swap
65
counterparty. Adding to our operating cash flow for the nine
months ended September 30, 2007 was a $43.2 million
source of cash related to a decrease in trade working capital.
For the nine months ended September 30, 2007, accounts
receivable decreased $4.2 million, inventory increased
$48.4 million and accounts payable increased
$87.4 million.
Cash
Flows Used in Investing Activities
Net cash used in investing activities for the nine months ended
September 30, 2008 was $67.4 million compared to
$239.7 million for the nine months ended September 30,
2007. The decrease in investing activities 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. The majority of these
capital projects, with the exception of the continuous catalytic
reforming unit, were completed during the nine months ended
September 30, 2007.
Cash
Flows Used In Financing Activities
Net cash used in financing activities for the nine months ended
September 30, 2008 was $8.0 million as compared to net
cash provided by financing activities of $59.4 million for
the nine months ended September 30, 2007. During the nine
months ended September 30, 2008, the principal use of cash
related to scheduled principal payments of $3.7 million on
long-term debt. The primary sources of cash for the nine months
ended September 30, 2007 were obtained through net
borrowings under the revolving credit facility of
$20.0 million and borrowings obtained from the
$25.0 million secured and the $25.0 million unsecured
credit facilities obtained to provide additional liquidity
during the completion of our restoration efforts for the
refinery and nitrogen operations as a result of the flood.
During the nine months ended September 30, 2007, we also
paid $3.9 million of scheduled principal payments on
long-term debt.
Working
Capital
Working capital at September 30, 2008, was
$73.6 million, consisting of $607.9 million in current
assets and $534.3 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 $115.1 million at September 30, 2008.
Letters
of Credit
Our revolving credit facility provides for the issuance of
letters of credit. At September 30, 2008, there were
$34.9 million of irrevocable letters of credit outstanding,
including $3.3 million in support of certain environmental
obligators and $31.6 million to secure transportation
services for crude oil.
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements as of
September 30, 2008.
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
September 30, 2008, the only financial assets and financial
liabilities that are within the scope of SFAS 157 and
measured at fair value on a recurring basis are the
Companys derivative instruments. See Note 15,
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
66
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 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.
Critical
Accounting Policies
The Companys critical accounting policies are disclosed in
the Critical Accounting Policies section of our
Annual Report on
Form 10-K/A
for the year ended December 31, 2007. In addition to the
accounting policies discussed in our 2007
Form 10-K/A,
the following accounting policy has been updated.
Receivables
From Insurance
As of September 30, 2008, we have incurred total gross
costs of approximately $154.6 million as a result of the
2007 flood and crude oil discharge. During this period, we have
maintained insurance 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 September 30,
2008, we have recognized receivables of approximately
$104.2 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
September 30, 2008, we have collected approximately
$49.5 million of these receivables. Subsequent to
September 30, 2008 we received an additional
$9.8 million advance payment for unallocated property
damage. As of November 6, 2008, the total amount of
insurance recoveries received was $59.3 million.
We have submitted voluminous claims information to, and continue
to respond to information requests from, 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 the Companys facilities are principally located
in Zone A, which was, at the time of the flood,
subject to a $10 million insurance limit for flood, or
Zone B which was, at the time of the flood, subject
to a $300 million insurance limit for flood. The Company
has reached an agreement with certain of its property insurers
representing approximately 32.5% of its total property coverage
for the flood-damaged facilities that our facilities are
principally located in Zone B and therefore subject
to the $300 million limit for flood. Our remaining property
insurers have not, at this time, agreed to this position. In
addition, our excess environmental liability insurance carrier
has asserted that our pollution liability claims are for
cleanup, which is not covered, rather than for
property damage, which is covered to the limits of
the policy. While we will vigorously contest the excess
carriers position, we contend that if that position were
upheld, our umbrella Comprehensive General Liability policies
would continue to provide coverage for these claims. Each
insurer, however, has reserved its rights under various policy
exclusions and limitations and has cited potential coverage
defenses. Ultimate recovery will be subject to litigation which
was filed in July 2008.
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.
67
Collective
Bargaining Agreements
We are a party to collective bargaining agreements which as of
September 30, 2008 covered approximately 39% of our
employees (all of whom work in our petroleum business) with the
six unions of the Metal Trades Department of the AFL-CIO
(Metal Trades Unions) and the United Steelworkers of
America. A new agreement was recently reached with the Metal
Trade Union effective August 31, 2008. The new agreement
will expire in March 2013. No substantial changes were made to
the agreement. The agreements with the United Steelworkers of
America are scheduled to expire in March 2009.
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Item 3.
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Quantitative
and Qualitative Disclosures About Market Risk
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The risk inherent in our market risk sensitive instruments and
positions is the potential loss from adverse changes in
commodity prices and interest rates. Information about market
risks for the nine months ended September 30, 2008 does not
differ materially from that discussed under
Part I Item 3 of our Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2008. We are exposed to
market pricing for all of the products sold in the future both
at our petroleum business and the nitrogen fertilizer business,
as all of the products manufactured in both businesses are
commodities. As of September 30, 2008, all
$485.5 million of outstanding debt under our credit
facility was at floating rates; accordingly, 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. None of our
market risk sensitive instruments are held for trading.
Our earnings and cash flows and estimates of future cash flows
are sensitive to changes in energy prices. The prices of crude
oil and refined products have fluctuated substantially in recent
years. These prices depend on many factors, including the
overall demand for crude oil and refined products, which in turn
depend on, among other factors, general economic conditions, the
level of foreign and domestic production of crude oil and
refined products, the availability of imports of crude oil and
refined products, the marketing of alternative and competing
fuels, the extent of government regulations and global market
dynamics. The prices we receive for refined products are also
affected by factors such as local market conditions and the
level of operations of other refineries in our markets. The
prices at which we can sell gasoline and other refined products
are strongly influenced by the price of crude oil. Generally, an
increase or decrease in the price of crude oil results in a
corresponding increase or decrease in the price of gasoline and
other refined products. The timing of the relative movement of
the prices, however, can impact profit margins, which could
significantly affect our earnings and cash flows.
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Item 4.
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Controls
and Procedures
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Evaluation
of Disclosure Controls and Procedures
We have established disclosure controls and procedures
(Disclosure Controls) to ensure that information required to be
disclosed in the Companys reports filed under the
Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods
specified in the SECs rules and forms. Disclosure Controls
are also designed to ensure that such information is accumulated
and communicated to management, including the Chief Executive
Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure. Our Disclosure
Controls were designed to provide reasonable assurance that the
controls and procedures would meet their objectives. Our
management, including the Chief Executive Officer and Chief
Financial Officer, does not expect that our Disclosure Controls
will prevent all error and fraud. A control system, no matter
how well designed and operated, can provide only reasonable
assurance of achieving the designed control objectives and
management is required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the
Company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty,
and that breakdowns can occur because of human error or mistake.
Additionally, controls can be circumvented by the individual
acts of some persons, by collusions of two or more people, or by
management override of the control. Because of the inherent
limitations in any control system, misstatements due to error or
fraud may occur and not be detected.
68
At March 31, 2008, we identified material weaknesses in our
internal controls relating to the calculation of the cost of
crude oil purchased by us and associated financial transactions.
Specifically, our policies and procedures for estimating the
cost of crude oil and reconciling these estimates to vendor
invoices were not effective. Additionally, our 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. 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.
In order to remediate the material weaknesses described above,
our management has been actively engaged in the planning for,
design, and implementation of remediation efforts to enhance
controls to ensure the proper accounting for the calculation of
the cost of crude oil. As a result of the plan and development
of the initiatives to remediate the material weaknesses, we have
centralized all crude oil cost accounting functions and have
added additional layers of accounting review with respect to our
crude oil cost accounting. Also, additional layers of business
review in conjunction with the accounting review of the
computation of our crude oil costs have been added. As of
September 30, 2008, the testing of the controls that have
been put in place was not completed and as a result, the
material weaknesses have not been fully remediated.
As of the end of the period covered by this
Form 10-Q,
we evaluated the effectiveness of the design and operation of
our Disclosure Controls and included consideration of the
material weaknesses initially disclosed in our Annual Report on
Form 10-K/A
for the year-ended December 31, 2007. The evaluation of our
Disclosure Controls was performed under the supervision and with
the participation of management, including our Chief Executive
Officer and Chief Financial Officer, and included consideration
of the material weaknesses described above. Based on this
evaluation, because the testing of the controls that have been
put in place has not been completed, our Chief Executive Officer
and Chief Financial Officer have concluded that our Disclosure
Controls and procedures were not effective as of the end of the
period covered by this Quarterly Report on
Form 10-Q
because of the material weaknesses described above.
Even in light of these material weaknesses, based on a number of
factors, including efforts to remediate the material weaknesses
discussed above and the performance of additional procedures by
management to ensure the reliability of our financial reporting,
we believe that the consolidated financial statements in the
report fairly present, in all material respects, our financial
position, results of operations, and cash flows as of the dates,
and for the periods presented, in conformity with generally
accepted accounting principles (GAAP).
We anticipate that the design, implementation, and required
testing of new processes and controls to remediate the material
weaknesses described above will be complete as of and for the
year ended December 31, 2008. The estimated costs
associated with the remediation efforts are approximately
$710,000, which amount includes a portion of the additional
payroll expense associated with the remediation efforts.
Changes
in Internal Control Over Financial Reporting
No changes in our internal control over financial reporting (as
defined in
Rules 13a-15(f)
and
15d-15(f)
under the Securities Exchange Act of 1934, as amended), except
with respect to changes made to remediate the material
weaknesses described above, occurred during the third quarter of
2008 that have materially affected, or are reasonably likely to
materially affect, our internal control over financial
reporting. We are, however, currently continuing remedial
actions to address the material weaknesses described above under
Evaluation of Disclosure Controls and
Procedures. In our efforts to remediate the material
weaknesses, management has engaged a third-party firm to assist
us in performing a comprehensive analysis of our control and
processes over the calculation and recording of crude oil
purchased by us.
During the second and third quarter, we began the implementation
of the remedial measures described above including the design
and implementation of additional key accounting controls and
processes related to the calculation of the cost of crude oil.
69
Part II.
Other Information
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Item 1.
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Legal
Proceedings
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The following supplements and amends our discussion set forth
under Item 3 Legal Proceedings in our Annual
Report on
Form 10-K/A
for the fiscal year ended December 31, 2007, and under
Item 1 Legal Proceedings in our Quarterly
Report on
Form 10-Q
for the quarter ended June 30, 2008.
As described in our quarterly report on
form 10-Q
for the quarter ended June 30, 2008, we filed two lawsuits
in the United States District Court for the District of Kansas
on July 10, 2008 against certain of our insurance carriers
with regard to our insurance coverage for the flood and crude
oil discharge that occurred during the weekend of June 30,
2007. In Coffeyville Resources Refining & Marketing,
LLC (CRRM), et al. v. National Union Fire Insurance Company
of Pittsburgh, PA, et al., we are seeking a declaratory judgment
against certain of our property insurers that our damaged
facilities are located principally in Zone B, which
was, at the time of the flood, subject to a $300 million
insurance limit for flood, and not in Zone A, which
was, at the time of the flood, subject to a $10 million
flood insurance limit. Property insurers representing
approximately 32.5% of our total property coverage for the flood
have agreed with our position that our property is located
principally in Zone B and have signed a settlement
agreement with us to the effect that our flood damaged property
is principally located in the areas subject to the
$300 million insurance limit for flood. In CRRM v.
Liberty Surplus Insurance Corporation, et al., we sued our
environmental insurance liability carriers for breach of
contract on the grounds that our pollution liability claims are
covered to the limits of our environmental pollution policies
and payment by the carriers under such policies has not been
made. Our primary environmental liability carrier subsequently
paid its full policy limit and has been dismissed from the
pollution insurance case.
Item 1A. Risk
Factors
See Risk Factors attached hereto as
Exhibit 99.1 for a discussion of risks our business may
face.
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Number
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Exhibit Title
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10
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.1
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Amendment to Amended and Restated Crude Oil Supply Agreement,
dated as of September 26, 2008, between Coffeyville Resources
Refining & Marketing, LLC and J. Aron & Company.
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10
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.2
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Amended and Restated Settlement Deferral Letter, dated as of
October 11, 2008, between Coffeyville Resources, LLC and J. Aron
& Company.
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10
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.3
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First Amendment to Amended and Restated On-Site Product Supply
Agreement, dated as of October 31, 2008, between Coffeyville
Resources Nitrogen Fertilizers, LLC and Linde, Inc.
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10
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.4
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Second Amendment to Amended and Restated Crude Oil Supply
Agreement dated as of October 31, 2008, between Coffeyville
Resources Refining & Marketing, LLC and J. Aron &
Company.
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31
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.1
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Rule 13a 14(a)/15d 14(a) Certification
of Chief Executive Officer
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31
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.2
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Rule 13a 14(a)/15d 14(a) Certification
of Chief Financial Officer
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32
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.1
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Section 1350 Certification of Chief Executive Officer and Chief
Financial Officer
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99
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.1
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Risk Factors
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70
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this
13th day
of November, 2008.
CVR Energy, Inc.
Chief Executive Officer
(Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
71
EX-10.1
Exhibit 10.1
AMENDMENT TO
AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT
THIS AMENDMENT TO AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT (this Amendment), dated as
of September 26, 2008, is made between J. Aron & Company, a general partnership organized under the
laws of New York (Supplier) and Coffeyville Resources Refining & Marketing, LLC, a limited
liability company organized under the laws of Delaware (Coffeyville).
Supplier and Coffeyville are parties to an Amended and Restated Crude Oil Supply Agreement
dated as of December 31, 2007 (the Supply Agreement). Coffeyville and Supplier have agreed to
amend certain terms and conditions of the Supply Agreement.
Accordingly, the Parties hereto agree as follows:
SECTION 1 Definitions; Interpretation.
(a) Terms Defined in Supply Agreement. All capitalized terms used in this Amendment
(including in the recitals hereof) and not otherwise defined herein have the meanings assigned to
them in the Supply Agreement.
(b) Interpretation. The rules of interpretation set forth in Section 1.2 of the
Supply Agreement apply to this Amendment and are incorporated herein by this reference.
SECTION 2 Amendment to the Supply Agreement.
(a) Amendment. As of the date of this Amendment, the Supply Agreement is amended by
deleting the first sentence of Section 3.2 of the Supply Agreement and inserting the following in
place thereof:
Unless either Party has delivered to the other a written notice of its election not
to extend this Agreement pursuant to this Section on or before October 31 of the
calendar year during the then current term, the Expiration Date will, without any
further action, be automatically extended, effective as of the Expiration Date as
then in effect, for an additional one year beyond the Expiration Date as then in
effect (each such period, an Extension Term; and the final day of such
Extension Term becoming the Expiration Date).
(b) References Within Supply Agreement. Each reference in the Supply Agreement to
this Agreement and the words hereof, herein, hereunder, or words of like import, are a
reference to the Supply Agreement as amended by this Amendment.
SECTION 3 Representations and Warranties. To induce the other Party to enter into
this Amendment, each Party hereby (i) confirms and restates, as of the date hereof, the
representations and warranties made by it in Article 16 or any other article or section of the
Supply Agreement and (ii) represents and warrants that no Event of Default or Potential Event of
Default with respect to it has occurred and is continuing.
SECTION 4 Miscellaneous.
(a) Supply Agreement Otherwise Not Affected. Except for the amendments pursuant
hereto, the Supply Agreement remains unchanged. As amended pursuant hereto, the Supply Agreement
remains in full force and effect and is hereby ratified and confirmed in all respects. The
execution and delivery of, or acceptance of, this Amendment and any other documents and instruments
in connection herewith by either Party will not be deemed to create a course of dealing or
otherwise create any express or implied duty by it to provide any other or further amendments,
consents or waivers in the future.
(b) No Reliance. Each Party hereby acknowledges and confirms that it is executing
this Amendment on the basis of its own investigation and for its own reasons without reliance upon
any agreement, representation, understanding or communication by or on behalf of any other Person.
(c) Costs and Expenses. Each Party is responsible for any costs and expenses incurred
by such Party in connection with the negotiation, preparation, execution and delivery of this
Amendment and any other documents to be delivered in connection herewith.
(d) Binding Effect. This Amendment will be binding upon, inure to the benefit of and
be enforceable by Coffeyville, Supplier and their respective successors and assigns.
(e) Governing Law. THIS AMENDMENT WILL BE GOVERNED BY, CONSTRUED AND ENFORCED UNDER
THE LAWS OF THE STATE OF NEW YORK WITHOUT GIVING EFFECT TO ITS CONFLICTS OF LAW PRINCIPLES THAT
WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER STATE.
(f) Amendments. This Amendment may not be modified, amended or otherwise altered
except by written instrument executed by the Parties duly authorized representatives.
(g) Effectiveness; Counterparts. This Amendment will become effective on the date
first written above. This Amendment may be executed in any number of counterparts and by different
Parties hereto in separate counterparts, each of which when so executed will be deemed to be an
original and all of which taken together constitute but one and the same agreement.
(h) Interpretation. This Amendment is the result of negotiations between and have
been reviewed by counsel to each of the Parties, and is the product of all Parties hereto.
Accordingly, this Amendment will not be construed against either Party merely because of such
Partys involvement in the preparation hereof.
The Parties hereto have duly executed this Amendment, as of the date first above written.
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J. ARON & COMPANY
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By: |
/s/ Andre Eriksson |
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Name: |
Andre Eriksson |
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Title: |
Managing Director |
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COFFEYVILLE RESOURCES REFINING &
MARKETING, LLC
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By: |
/s/ James T. Rens |
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Name: |
James T. Rens |
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Title: |
CFO |
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EX-10.2
Exhibit 10.2
Execution Version
October 11, 2008
Coffeyville Resources, LLC
10 East Cambridge Circle, Suite #250
Kansas City, Kansas 66103
Attention: Tim Rens
Telecopier: (913) 981-0000
Re: Amended and Restated Settlement Deferral
Ladies and Gentlemen:
This amended and restated settlement deferral letter (including all attachments hereto)
amends, restates and supersedes that certain revised settlement deferral letter dated July
29, 2008 (the Original Settlement Deferral Letter) from J. Aron & Company
(Aron) to Coffeyville Resources, LLC (the Company).
We refer to the letter from us to you dated June 26, 2007 (the Initial Deferral
Letter), providing for the deferral of certain amounts due under the Transactions (as
defined therein). Further reference is made to the letters dated July 9, 2007, July 11,
2007, July 26, 2007 and August 23, 2007 (collectively, with the Initial Deferral Letter,
the 2007 Deferral Letters) relating to the matters set forth in the Initial
Deferral Letter.
Capitalized terms not otherwise defined herein shall have the meaning set forth in the
2007 Deferral Letters. Notwithstanding the foregoing sentence, terms used in clause (d)
below and not otherwise defined in the 2007 Deferral Letters shall have the meaning set
forth in the Second Amended and Restated Credit and Guaranty Agreement, dated as of
December 28, 2006, among the Company, certain affiliates of the Company, the lenders party
thereto from time to time, GSCP and Credit Suisse Securities (USA) LLC, as joint lead
arrangers and joint bookrunners, Credit Suisse, as administrative agent, collateral agent,
funded L/C issuing bank and as revolving issuing bank, Deutsche Bank Trust Company
Americas, as syndication agent and ABN AMRO Bank N.V., as documentation agent (as amended
through the date hereof, the 2006 Credit Agreement).
You have requested that we permit you to defer further certain of the Deferred Amounts
owed under the 2007 Deferral Letters (the Deferred Amounts), which amounts the
parties acknowledge and agree shall, as of the Effective Date (as defined below), after
giving effect to payments required on or prior to the Effective Date, not exceed
$72,500,000 in the aggregate.
Aron is prepared to extend the deferral of such portion of the Deferred Amounts as provided herein
subject to the following terms and conditions:
(a) on December 15, 2008 (the Effective
Date), the Company shall have paid to Aron all outstanding accrued interest on the Deferred
Amounts that remains unpaid through the Effective Date, at the rate of one-month
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Coffeyville Resources, LLC
October 11, 2008
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LIBOR (as determined by Aron) plus 2.75% (compounded on the last Local
Business Day of each month);
(b) each of the Guarantors shall have, on the date of this letter
agreement, reaffirmed its guaranty of one half of the Deferred Amounts by
executing and delivering to us a reaffirmation of its respective Guaranty
Agreement, dated as of August 23, 2007, in the forms attached as Appendices
A and B to this letter agreement (each, a Reaffirmation and
collectively, the Reaffirmations);
(c) Interest shall accrue and be payable on the unpaid Deferred Amounts from
(and including) the Effective Date to (but excluding) the date of actual
payment, at the rate of LIBOR with a one-month interest period (as
determined by Aron) plus the Applicable Spread (as defined below), such
interest to compound on the last Local Business Day of each month. For the
purposes of this clause (c), the Applicable Spread means the
sum of (x) the one-year spread on the credit default swaps for
senior unsecured debt of The Goldman Sachs Group, Inc., as such spread is
reasonably determined by Aron on the Effective Date, plus (y) 200
basis points (provided that, if the Applicable Spread would
otherwise be greater than 750 basis points, it shall be deemed to be 750
basis points, and if the Applicable Spread would otherwise be less than 500
basis points, it will be deemed to be 500 basis points);
(d) the Company shall, no later than the last Local Business Day (as
defined in the Agreement) of each calendar quarter ending March 31, 2009 and
June 30, 2009, pay $5,000,000 to reduce the balance of the Deferred Amounts
and interest thereon;
(e) to the extent that after the date of this letter agreement the Company
or any of its Subsidiaries (i) receive net insurance proceeds relating to
the flooding of the plant (and other flood-related damages) in July 2007 and
(ii) are not required to apply such proceeds in prepayment of debt incurred
under the 2006 Credit Agreement or to further invest such proceeds in
accordance with the 2006 Credit Agreement or otherwise become entitled to
use such proceeds for general corporate purposes, the Company shall apply
all such proceeds received by it to the Deferred Amounts and interest
thereon no later than three Local Business Day following such receipt; and
(f) the unpaid Deferred Amounts, all accrued and unpaid interest thereon and
all other amounts payable hereunder shall, notwithstanding anything herein
or in the 2007 Letter Agreements to the contrary, be due and payable in full
on July 31, 2009 (the Maturity Date). If the Company violates any
provision of this letter agreement, the Deferred Amounts, all accrued
interest thereon and all other amounts owed hereunder shall become
immediately due and payable upon notice from Aron. The parties acknowledge
and agree that failure to make such payment pursuant to
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Coffeyville Resources, LLC |
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October 11, 2008
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this clause (f) shall constitute an Event of Default under Section 5(a)(i) of
the Agreement; provided that the phrase if such failure is not
remedied on or before the third Local Business Day after notice of such failure
is given to the party at the end of Section 5(a)(i) is hereby deleted in
relation to this clause (f).
All payments made hereunder shall be applied, first, to pay accrued and unpaid interest, and,
second, to repay the Deferred Amounts.
The parties acknowledge and agree that, as of the date of this letter agreement, the Deferred
Amounts are equal to $72,500,000 in the aggregate, and accrued interest thereon equals
$516,112.22, and that there are no defenses to payment of such amounts by the Company.
The Agreement is hereby amended, for so long as the Guaranty Agreements (as amended and
reaffirmed by the applicable Reaffirmation) are in effect, as follows:
Section 4(f) of the Schedule to the Agreement is amended to delete the sentence added to
such Section pursuant to the letters dated July 11, 2007, July 26, 2007 and August 23,
2007 and to add the following as clause (v) to such Section: (v) The Guaranty
Agreements, each dated as of August 23, 2007 and as amended and reaffirmed by the
Reaffirmations, each dated as of July 29, 2008, delivered pursuant to the Letter
Agreement dated July 29, 2008 between Aron and Counterparty.
This letter agreement may be executed in any number of counterparts, each of which shall
constitute an original, but all of which, taken together, shall be deemed to constitute one
and the same agreement. This letter agreement supersedes the Original Settlement Deferral
Letter in full and, upon execution of this letter agreement, the Original Settlement Deferral
Letter will no longer have any force or effect. Except as expressly modified and extended
hereby, the 2007 Deferral Letters shall remain in full force and effect and shall not be
modified or novated hereby. Except as expressly amended hereunder, the Agreement, the
Transactions and the Confirmations shall remain in full force and effect and shall not be
modified or novated hereby.
THIS LETTER AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF NEW YORK (WITHOUT REFERENCE TO ANY CONFLICT OF LAW RULES).
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J. ARON & COMPANY |
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By:
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/s/ Jeff Resnick
Name: Jeff Resnick
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Title: Managing Director |
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ACCEPTED
AND AGREED TO THIS 11th DAY OF OCTOBER, 2008.
COFFEYVILLE RESOURCES, LLC
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By:
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/s/ John J. Lipinski
Name: John J. Lipinski |
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Title: CEO |
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Appendix A
Reaffirmation of GSCP V Guaranty dated August 23, 2007
[attached separately]
Execution Version
REAFFIRMATION OF GUARANTY
As consideration for the agreements and covenants contained in that certain letter agreement
regarding Amended and Restated Settlement Deferral dated as of October 11, 2008 (the Amended
and Restated Settlement Deferral Letter), between J. Aron & Company (Counterparty)
and Coffeyville Resources, LLC (the Company), and for other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, the undersigned (Guarantor),
as guarantor under that certain Guaranty Agreement, dated as of August 23, 2007 (the
Guaranty), delivered to Counterparty in connection with the letter dated August 23,
2007, from Counterparty to the Company and attached hereto as Appendix A, hereby acknowledges,
covenants and agrees as follows:
1. Notwithstanding anything to the contrary in the Guaranty, references to the Revised Letter
Agreement therein shall be deemed to include such Revised Letter Agreement as further amended and
modified by the Amended and Restated Settlement Deferral Letter.
2. The Guarantor consents to the terms of the Amended and Restated
Settlement Deferral Letter and confirms that the Guaranty remains in full force and effect,
without modification (except as expressly set forth herein) or novation, notwithstanding any
provision of the Guaranty to the contrary.
3. The Guarantor reaffirms all of the obligations contained in the Guaranty, and specifically
agrees that the Obligations (as defined in the Guaranty) include the full repayment of 50% of the
Deferred Amounts (as defined in the Amended and Restated Settlement Deferral Letter) plus accrued
and unpaid interest (as provided in the Amended and Restated Settlement Deferral Letter) upon such
dates as set forth in the Amended and Restated Settlement Deferral Letter, and acknowledges,
agrees, represents and warrants that no agreements exist with respect to the Guaranty or with
respect to the obligations of Guarantor thereunder except those specifically set forth therein and
in this Reaffirmation.
4. Each of the representations and warranties of the Guarantor contained or incorporated in
the Guaranty is true and correct on and as of the date hereof.
5. The Guaranty is hereby amended by adding the following paragraphs before the first full
paragraph on page 3 thereof:
(A) Subject to the obligation to make a pro rata request for payment
under the Kelso Guaranty, the obligations of the Guarantor hereunder are independent of the
obligations of the Company and the obligations of any other guarantor (including any other
Guarantor) of the obligations of the Company, and a separate action or actions may be brought and
prosecuted against the Guarantor whether or not any action is brought against the Company or any
of such other guarantors and whether or not Company is joined in any such action or actions;
(B)
Payment by the Guarantor of a portion, but not all, of the Obligations shall in no way limit,
affect, modify or abridge the Guarantors liability for any portion of the Obligations which has
not been paid.
(C) Until the Obligations shall have been indefeasibly paid in full, the Guarantor hereby
waives any claim, right or remedy, direct or indirect, that it now has or may hereafter
have against the Company or any other guarantor or any of its assets in connection with
this Guaranty or the performance by the Guarantor of its obligations hereunder, in each
case, whether such claim, right or remedy arises in equity, under contract, by statute,
under common law or otherwise and including (a) any right of subrogation, reimbursement or
indemnification that the Guarantor now has or may hereafter have against the Company with
respect to the Obligations, (b) any right to enforce, or to participate in, any claim,
right or remedy that Counterparty now has or may hereafter have against the Company, and
(c) any benefit of, and any right to participate in, any collateral or security now or
hereafter held by Counterparty. The Guarantor further agrees that, to the extent the
waiver or agreement to withhold the exercise of its rights of subrogation, reimbursement
and indemnification as set forth herein is found by a court of competent jurisdiction to
be void or voidable for any reason, any rights of subrogation, reimbursement or
indemnification the Guarantor may have against the Company or against any collateral or
security shall be junior and subordinate to any rights Counterparty may have against the
Company, to all right, title and interest Counterparty may have in any such collateral or
security. If any amount shall be paid to the Guarantor on account of any such subrogation,
reimbursement or indemnification rights at any time when all Obligations shall not have
been finally and indefeasibly paid in full, such amount shall be held in trust for
Counterparty and shall forthwith be paid over to Counterparty to be credited and applied
against the Obligations, whether matured or unmatured, in accordance with the terms
hereof.
(D) The Guarantor agrees to pay on demand all costs and expenses of Counterparty, if any
(including, without limitation, reasonable counsel fees and expenses), in connection with
the enforcement (whether through negotiations, legal proceedings or otherwise) of this
Guaranty.
(E) The Guarantor agrees not to assert any claim for special, indirect, consequential or
punitive damages against Counterparty, any of its affiliates, or any of its directors,
officers, partners, employees, attorneys and agents, on any theory of liability, arising
out of or otherwise relating to this Guaranty or any of the transactions contemplated
herein.
(F) Subject to the Guarantors receipt of consent from the Arrangers and the Requisite
Lenders under, and as such terms are defined in, the 2006 Credit Agreement (as defined in
the Amended and Restated Settlement Deferral Letter) or delivery by the Guarantor to
Counterparty of an opinion of counsel reasonably acceptable to Counterparty to the effect
that no such consent is required (in each case, at the sole cost and expense of the
Guarantor), Counterparty agrees that in lieu of making payments when due pursuant to this
Guaranty, the Guarantor shall have the option to purchase (or to purchase, on a ratable
basis with Kelso, if so elected by Kelso pursuant to the terms of the Kelso Guaranty) on
such date all, but not less than all, of the Obligations at 100% of par value plus all
accrued interest thereon and other amounts owed with respect thereto, without
representation or warranty or recourse. The Guarantor agrees that any rights in the
Obligations which it acquires pursuant to this provision will be junior in right of
payment and priority to the rights of Counterparty under the ISDA Master Agreement between
the
2
Company and Counterparty dated as of June 24, 2005 and the Schedule to the ISDA Master
Agreement dated as of June 24, 2005 (each as amended by the Amended and Restated Settlement
Deferral Letter) and any pari passu obligations.
6. The Guarantor hereby consents to the amendment of the Kelso Guaranty dated as of the date
hereof in form and substance substantially similar to this Reaffirmation.
This Reaffirmation of Guaranty and the interpretation hereof shall be governed by, and
construed in accordance with, the internal laws of the State of New York.
[SIGNATURES APPEAR ON NEXT PAGE]
3
IN WITNESS WHEREOF, the Guarantor has caused this Reaffirmation of Guaranty to be duly
executed and delivered as of the date first written above.
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GS Capital Partners V, L.P. |
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By:
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GS Advisors V, L.L.C., its General Partner |
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By:
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/s/ Kenneth A. Pontarelli
Authorized Officer
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Appendix A
Guaranty
[attached separately]
August 23, 2007
J. Aron & Company
85 Broad Street
New York, New York 10004
Ladies and Gentlemen:
For value received, GS Capital Partners V, L.P., a limited partnership duly organized under the
laws of the State of Delaware (GSCP V or the Guarantor) hereby unconditionally guarantees the
prompt and complete payment, whether by acceleration or otherwise, of 50% of the Deferred Amounts
(as defined in the Revised Letter Agreement referred to below) plus accrued and unpaid interest (as
provided in such Revised Letter Agreement) (collectively, the Obligations) of Coffeyville
Resources, LLC, a limited liability company that is owned by affiliates of GSCP V, Kelso Investment
Associates VII, L.P. (Kelso), and certain members of the management of the Company (as defined
below) and is duly organized under the laws of the State of Delaware (the Company), to J. Aron &
Company (the Counterparty) under the ISDA Master Agreement between the Company and the
Counterparty dated as of June 24, 2005 and the Schedule to the ISDA Master Agreement dated as of
June 24, 2005 (each as amended by the letter agreements referred to in the Revised Letter
Agreement) under the Letter Agreement from the Counterparty to the Company, dated
August 23, 2007 (without giving effect to any further amendments thereto, the Revised Letter Agreement). Both
the Counterparty and the Guarantor agree and acknowledge that upon execution of this Guaranty, the
previous Guaranty of the Guarantor, dated as of July 26, 2007, will automatically terminate. GSCP V
shall receive on or prior to the date of this Guaranty a copy of the guarantee provided by Kelso
dated as of August 23, 2007 (as amended from time to time, the Kelso Guaranty). GSCP V authorizes
the Counterparty to provide a copy of this Guaranty to Kelso.
Counterparty agrees that at any time that a payment is requested under this Guaranty,
Counterparty shall make a pro rata request for payment under the Kelso Guaranty and the Guarantor
shall at no time be required to pay an amount in excess of its pro rata share of the aggregate
amount of payment required at such time. This Guaranty is one of payment and not of collection.
The Guarantor hereby waives notice of acceptance of this Guaranty and notice of any obligation or
liability to which it may apply, and waives presentment, demand for payment, protest, notice of
dishonor or non-payment of any such obligation or liability, suit or the taking of other action by
Counterparty against, and any other notice to, the Company, the Guarantor or others.
The Guarantor represents and warrants that it will have sufficient cash and available capital
commitments, amounts available for retention or recall by the Guarantor and/or other sources of
liquidity to make payment of the Obligations, (2) the Guarantors Guaranteed Obligations under and
as defined in the Guaranty made in connection with the 2007 Credit Agreement (as defined in the
Revised Letter Agreement), (3) the Guarantors Guaranteed Obligations under and as defined in the
Guaranty made in connection with the Unsecured Credit and Guaranty Agreement, dated as of August
23, 2007, among the Company, the guarantors party thereto, the lenders party thereto from time to
time, and GSCP, as sole lead arranger, sole bookrunner and administrative agent, and (4) the
Guarantors Guaranteed Obligations under and as defined in the Guaranty made in connection with the
Unsecured Credit and Guaranty Agreement, dated as of August 23,
2007, among Coffeyville Refining &
Marketing Holdings, Inc., as the borrower, the guarantors party thereto, the lenders party thereto
from time to time, and GSCP as sole lead arranger, sole bookrunner, and administrative agent, in
each case, when such obligations are due and payable.
Counterparty may at any time and from time to time without notice to or consent of the Guarantor
and without impairing or releasing the obligations of the Guarantor hereunder: (1) agree with the
Company to make any change in the terms of any obligation or liability of the Company to
Counterparty (provided that the Counterparty shall obtain the consent of the Guarantor, such
consent not to be unreasonably withheld, prior to making a change that would cause the Deferred
Amounts (as defined in the Letter Agreement), excluding interest thereon and the Accrued Interest,
to exceed $124,700,000), (2) take or fail to take any action of any kind in respect of any security
for any obligation or liability of the Company or any other guarantor to Counterparty, (3) exercise
or refrain from exercising any rights against the Company or others, (4) release, surrender,
compromise, settle, rescind, waive alter, subordinate or modify and other guaranties of the
Obligations or (5) compromise or subordinate any obligation or liability of the Company to
Counterparty including any security therefor. Any other suretyship defenses are hereby waived by
the Guarantor.
This Guaranty is irrevocable and shall remain in full force and effect and be binding upon
Guarantor, its successors and assigns, until all of the Obligations have been satisfied in full.
The Guarantor further agrees that this Guaranty shall continue to be effective or be reinstated, as
the case may be, if at any time payment or any part thereof, of any Obligations payable by it or
interest thereon, is rescinded or must otherwise be restored or returned by Counterparty upon the
bankruptcy, insolvency, dissolution or reorganization of the Company.
The Guarantor may not assign its rights nor delegate its obligations under this Guaranty, in whole
or in part, without prior written consent of the Counterparty, and any purported assignment or
delegation absent such consent is void, except for (1) one or more assignments and delegations of
all or a portion of its obligations hereunder to any of GS Capital Partners V Institutional, L.P.,
GS Capital Partners V Offshore, L.P., GS Capital Partners V GmbH & Co. KG., GS Capital Partners V
Fund, L.P., GS Capital Partners V Employee Fund, L.P., and GS Capital Partners V Offshore Fund,
L.P. such
-2-
that each such fund has assumed by contract its pro rata
portion of the Obligations and/or (2)
an assignment and delegation of all of the Guarantors rights and obligations hereunder in whatever
form the Guarantor determines may be appropriate to a partnership, corporation, trust or other
organization in whatever form that succeeds to all or substantially all of the Guarantors assets
and business and that assumes such obligations by contract, operation of law or otherwise. Upon
any such delegation and assumption of obligations; the Guarantor shall be relieved of and fully
discharged from all obligations hereunder, whether such obligations arose before or after such
delegation and assumption.
The Guarantor acknowledges that the
Kelso Guaranty may not be amended or waived nor
any/consent or departure be effective without its prior written consent. Guarantor agrees that any
such consent shall not be unreasonably withheld.
No amendment or waiver of any
provision of this Guaranty nor consent to any departure by the
Guarantor herefrom shall in any event be effective unless the same shall be in writing and
signed by the Guarantor and the Counterparty, and which amendment,
waiver, consent or departure shall be consented to by Kelso.
THIS
GUARANTY SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE
WITH THE INTERNAL LAWS OF THE STATE
OF NEW YORK WITHOUT GIVING EFFECT TO PRINCIPLES OF CONFLICTS OF LAW. THE GUARANTOR AGREES TO THE
EXCLUSIVE JURISDICTION OF COURTS LOCATED IN THE STATE OF NEW YORK, UNITED STATES OF AMERICA, OVER
ANY DISPUTES ARISING UNDER OR RELATING TO THIS GUARANTY.
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Very truly yours,
GS Capital Partners V, L.P.
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GS Advisors V, L.L.C.
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its General Partner |
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/s/ Kaca Enquist
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Authorized Officer |
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Appendix B
Reaffirmation of Kelso Guaranty dated August 23, 2007
[attached separately]
Execution Version
REAFFIRMATION OF GUARANTY
As consideration for the agreements and covenants contained in that certain letter agreement
regarding Amended and Restated Settlement Deferral dated as of October 11, 2008 (the Amended
and Restated Settlement Deferral Letter), between J. Aron & Company (Counterparty)
and Coffeyville Resources, LLC (the Company), and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the undersigned
(Guarantor), as guarantor under that certain Guaranty Agreement, dated as of August 23,
2007 (the Guaranty), delivered to Counterparty in connection with the letter dated
August 23, 2007, from Counterparty to the Company and attached hereto as Appendix A, hereby
acknowledges, covenants and agrees as follows:
1. Notwithstanding anything to the contrary in the Guaranty, references to the Revised Letter
Agreement therein shall be deemed to include such Revised Letter Agreement as further amended and
modified by the Amended and Restated Settlement Deferral Letter.
2. The Guarantor consents to the terms of the Amended and Restated
Settlement Deferral Letter and confirms that the Guaranty remains in full force and effect,
without modification (except as expressly set forth herein) or novation, notwithstanding any
provision of the Guaranty to the contrary.
3. The Guarantor reaffirms all of the obligations contained in the Guaranty, and specifically
agrees that the Obligations (as defined in the Guaranty) include the full repayment of 50% of the
Deferred Amounts (as defined in the Amended and Restated Settlement Deferral Letter) plus accrued
and unpaid interest (as provided in the Amended and Restated Settlement Deferral Letter) upon such
dates as set forth in the Amended and Restated Settlement Deferral Letter, and acknowledges,
agrees, represents and warrants that no agreements exist with respect to the Guaranty or with
respect to the obligations of Guarantor thereunder except those specifically set forth therein and
in this Reaffirmation.
4. Each of the representations and warranties of the Guarantor contained or incorporated in
the Guaranty is true and correct on and as of the date hereof.
5. The Guaranty is hereby amended by adding the following paragraphs before the first full
paragraph on page 3 thereof:
(A) Subject to the obligation to make a pro rata request for payment
under the GSCP V Guaranty, the obligations of the Guarantor hereunder are independent of the
obligations of the Company and the obligations of any other guarantor (including any other
Guarantor) of the obligations of the Company, and a separate action or actions may be brought and
prosecuted against the Guarantor whether or not any action is brought against the Company or any of
such other guarantors and whether or not Company is joined in any such action or actions;
(B)
Payment by the Guarantor of a portion, but not all, of the Obligations shall in no way limit,
affect, modify or abridge the Guarantors liability for any portion of the Obligations which has
not been paid.
(C) Until the Obligations shall have been indefeasibly paid in full, the Guarantor
hereby waives any claim, right or remedy, direct or indirect, that it now has or may
hereafter have against the Company or any other guarantor or any of its assets in
connection with this Guaranty or the performance by the Guarantor of its obligations
hereunder, in each case, whether such claim, right or remedy arises in equity, under
contract, by statute, under common law or otherwise and including (a) any right of
subrogation, reimbursement or indemnification that the Guarantor now has or may
hereafter have against the Company with respect to the Obligations, (b) any right to
enforce, or to participate in, any claim, right or remedy that Counterparty now has or may
hereafter have against the Company, and (c) any benefit of, and any right to participate
in, any collateral or security now or hereafter held by Counterparty. The Guarantor
further agrees that, to the extent the waiver or agreement to withhold the exercise of its
rights of subrogation, reimbursement and indemnification as set forth herein is found by a
court of competent jurisdiction to be void or voidable for any reason, any rights of
subrogation, reimbursement or indemnification the Guarantor may have against the
Company or against any collateral or security shall be junior and subordinate to any
rights Counterparty may have against the Company, to all right, title and interest
Counterparty may have in any such collateral or security. If any amount shall be paid to
the Guarantor on account of any such subrogation, reimbursement or indemnification
rights at any time when all Obligations shall not have been finally and indefeasibly paid
in full, such amount shall be held in trust for Counterparty and shall forthwith be paid
over to Counterparty to be credited and applied against the Obligations, whether matured
or unmatured, in accordance with the terms hereof.
(D) The Guarantor agrees to pay on demand all costs and expenses of Counterparty, if
any (including, without limitation, reasonable counsel fees and expenses), in connection
with the enforcement (whether through negotiations, legal proceedings or otherwise) of
this Guaranty.
(E) The Guarantor agrees not to assert any claim for special, indirect, consequential or
punitive damages against Counterparty, any of its affiliates, or any of its directors,
officers, partners, employees, attorneys and agents, on any theory of liability, arising out
of or otherwise relating to this Guaranty or any of the transactions contemplated herein.
(F) Subject to the Guarantors receipt of consent from the Arrangers and the Requisite
Lenders under, and as such terms are defined in, the 2006 Credit Agreement (as defined
in the Amended and Restated Settlement Deferral Letter) or delivery by the Guarantor to
Counterparty of an opinion of counsel reasonably acceptable to Counterparty to the effect
that no such consent is required (in each case, at the sole cost and expense of the
Guarantor), Counterparty agrees that in lieu of making payments when due pursuant to
this Guaranty, the Guarantor shall have the option to purchase (or to purchase, on a
ratable basis with GSCP V, if so elected by GSCP V pursuant to the terms of the GSCP V
Guaranty) on such date all, but not less than all, of the Obligations at 100% of par value
plus all accrued interest thereon and other amounts owed with respect thereto, without
representation or warranty or recourse. The Guarantor agrees that any rights in the
Obligations which it acquires pursuant to this provision will be junior in right of payment
and priority to the rights of Counterparty under the ISDA Master Agreement between the
2
Company and Counterparty dated as of June 24, 2005 and the Schedule to the ISDA
Master Agreement dated as of June 24, 2005 (each as amended by the Amended and
Restated Settlement Deferral Letter) and any pari passu obligations.
6. The Guarantor hereby consents to the amendment of the GSCP V
Guaranty dated as of the date hereof in form and substance substantially similar to this
Reaffirmation.
This Reaffirmation of Guaranty and the interpretation hereof shall be governed by, and
construed in accordance with, the internal laws of the State of New York.
[SIGNATURES APPEAR ON NEXT PAGE]
3
IN WITNESS WHEREOF, the Guarantor has caused this Reaffirmation of Guaranty to be duly
executed and delivered as of the date first written above.
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Kelso Investment Associates VII, L.P.
By: Kelso GP VII, L.P., its General Partner
By: Kelso GP VII, LLC, its General Partner
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/s/
James J. Connors, II
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Appendix A
Guaranty
[attached separately]
August 23, 2007
J. Aron & Company
85 Broad Street
New York, New York 10004
Ladies and Gentlemen:
For value received, Kelso Investment Associates VII, L.P., a limited partnership duly
organized under the laws of the State of Delaware (Kelso or the Guarantor) hereby
unconditionally guarantees the prompt and complete payment, whether by acceleration or
otherwise, of 50% of (i) the Deferred Amounts (as defined in the Revised Letter Agreement
referred to below) and (ii) accrued and unpaid interest thereon (as provided in such Revised
Letter Agreement) (collectively, the Obligations) by Coffeyville Resources, LLC, a limited
liability company that is owned by Kelso, GS Capital Partners V, L.P. (GSCP V) and certain
members of the management of the Company (as defined below) and is duly organized under the
laws of the State of Delaware (the Company), to J. Aron & Company (the Counterparty) under
the ISDA Master Agreement between the Company and the Counterparty
dated as of June 24, 2005
and the Schedule to the ISDA Master Agreement dated as of June 24, 2005 (each as amended by
the letter agreements referred to in the Revised Letter Agreement) that are due in accordance
with the Letter Agreement from the Counterparty to the Company, dated August 23, 2007 (the
Revised Letter Agreement) within 12 days following receipt by the Guarantor of a written
request from the Counterparty. Both the Counterparty and the Guarantor agree and acknowledge
that upon execution of this Guaranty, the previous Guaranty of the Guarantor, dated as of July
26, 2007, will automatically terminate. Kelso shall receive on or prior to the date of this
Guaranty a copy of the guarantee provided by GSCP V dated as of August 23, 2007 (as amended
from time to time, the GSCP V Guaranty). Kelso authorizes the Counterparty to provide a copy
of this Guaranty to GSCP V.
The Counterparty agrees that at any time that a payment is requested under this Guaranty, the
Counterparty shall make a pro rata request for payment under the GSCP V Guaranty and the
Guarantor shall at no time be required to pay an amount in excess of its pro rata share of
the aggregate amount of payment required at such time. This Guaranty is one of payment and
not of collection.
The Guarantor hereby waives notice of acceptance of this Guaranty and notice of any
obligation or liability to which it may apply, and waives presentment, demand for payment,
protest, notice of dishonor or non-payment of any such obligation or liability, suit or the
taking of other action by the Counterparty against, and any other notice to, the Company, the
Guarantor or others.
The Guarantor represents and warrants that it has sufficient cash and available capital
commitments to make payment of each of (1) the Obligations, (2) the Guarantors Guaranteed
Obligations under and as defined in the Guaranty made in
connection with the 2007 Credit Agreement (as defined in the Revised Letter Agreement), (3)
the Guarantors Guaranteed Obligations under and as defined in the Guaranty made in
connection with the Unsecured Credit and Guaranty Agreement, dated as of August 23, 2007,
among the Company, the guarantors party thereto, the lenders party thereto from time to time,
and GSCP, as sole lead arranger, sole bookrunner and administrative agent, and (4) the
Guarantors Guaranteed Obligations under and as defined in the Guaranty made in connection
with the Unsecured Credit and Guaranty Agreement, dated as of August 23, 2007, among
Coffeyville Refining & Marketing Holdings, Inc., as the borrower, the guarantors party
thereto, the lenders party thereto from time to time, and GSCP as sole lead arranger, sole
bookrunner, and administrative agent (the obligations in clause (1) through (4), collectively
the Aggregate Obligations), in each case when such obligations are due and payable, and
covenants to maintain such cash and available capital commitments until satisfaction and
release of all obligations of the Guarantor hereunder. The Guarantor agrees to provide the
Counterparty, within 10 days following a written request from the Counterparty, a written
statement, certified by a senior financial officer of the Guarantor, setting forth the
outstanding unencumbered cash and unutilized capital commitments of the Guarantor at the end
of such calendar quarter.
Without limiting the Guarantors obligations under the immediately preceding paragraph,
the Guarantor and its respective general partners agree to take all action as may be
necessary so that, at any and all times prior to the satisfaction and release of all
obligations of the Guarantor under this Guaranty pursuant to the terms hereof, the Guarantor
and/or its general partners shall have caused its or their respective affiliates to reserve
capital in amounts sufficient to fund in a timely manner all obligations of the Guarantor
under the this Guaranty.
The Counterparty may at any time and from time to time without notice to or consent of the
Guarantor and without impairing or releasing the obligations of the Guarantor hereunder: (1)
agree with the Company to make any change in the terms of any obligation or liability of the
Company to the Counterparty, (2) take or fail to take any action of any kind in respect of
any security for any obligation or liability of the Company or any other guarantor to the
Counterparty, (3) exercise or refrain from exercising any rights against the Company or
others, (4) release, surrender, compromise, settle, rescind, waive alter, subordinate or
modify any other guaranties of the Obligations or (5) compromise or subordinate any
obligation or liability of the Company to the Counterparty including any security therefor;
provided that notwithstanding the foregoing, the Counterparty shall not, without the consent
of the Guarantor (i) change the duration of the deferral provided in the Revised Letter
Agreement, (ii) increase the Deferred Amounts (as defined in the Revised Letter Agreement),
(iii) otherwise amend, waive or modify
-2-
any other provision of the Revised Letter Agreement or (iv) take any affirmative action to release
any Collateral (as defined in the 2006 Credit Agreement (as defined in the Revised
Letter Agreement)). Any other suretyship defenses are hereby waived by the Guarantor
This Guaranty is irrevocable and shall remain in full force and effect and be binding upon
the Guarantor, and its successors and assigns, until all of the Obligations have been
satisfied in cash in full (the date on which the Obligations are so satisfied being the
Satisfaction Date). The Guarantor further agrees that this Guaranty shall continue to be
effective or be reinstated, as the case may be, if at any time payment or any part thereof,
of any Obligations or interest thereon, is rescinded or must otherwise be restored or
returned by the Counterparty; provided, however, that this sentence shall cease to be
operative on the earlier of (i) the date twelve months plus one calendar day after the
Satisfaction Date (if within such period (a) the Company has not become a debtor under the
United States Bankruptcy Code 11 U.S.C. § 101 et seq. (as now and hereafter in effect, or any
successor statute) or any similar State or Federal statue and (b) no action has been brought
against the Counterparty seeking to recover or rescind any such payment) and (ii) the date,
following the Satisfaction Date, when the Company consummates initial public offering of the
Companys common stock following which the Companys common stock is listed on any
internationally recognized exchange of dealer quotation system, all or a portion of the net
proceeds of which are used to pay or prepay at least $280,000,000 of the Companys
indebtedness (a Qualified IPO); provided that if a Qualified IPO occurs prior to the
Satisfaction Date, the obligations hereunder shall terminate on the Satisfaction Date.
The Guarantor may not assign its rights nor delegate its obligations under this Guaranty, in whole
or in part, without prior written consent of the Counterparty, and any purported assignment or
delegation absent such consent is void, except for an assignment and delegation of all of the
Guarantors rights and obligations hereunder in whatever form the Guarantor determines may be
appropriate to a partnership, corporation, trust or other organization in whatever form that
succeeds to all or substantially all of the Guarantors assets and business and that assumes such
obligations by contract, operation of law or otherwise. Upon any such delegation and assumption of
obligations, the Guarantor shall be relieved of and fully discharged from all obligations
hereunder, whether such obligations arose before or after such delegation and assumption.
Each of the Guarantor and the Counterpart acknowledges that the GSCP V Guaranty may not be amended
or waived nor any consent or departure be effective without the Guarantors prior written consent.
The Guarantor agrees that any such consent shall not be unreasonably withheld.
No amendment or waiver of any provision of this Guaranty nor consent to any departure by
the Guarantor herefrom shall in any event be effective unless the
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same shall
be in writing and signed by the Guarantor and the Counterparty, and which amendment,
waiver, consent or departure shall be consented to by GSCP V.
THIS GUARANTY SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE
OF NEW YORK WITHOUT GIVING EFFECT TO PRINCIPLES OF CONFLICTS OF LAW. THE GUARANTOR AGREES TO THE
EXCLUSIVE JURISDICTION OF COURTS LOCATED IN THE STATE OF NEW YORK, UNITED STATES OF AMERICA, OVER
ANY DISPUTES ARISING UNDER OR RELATING TO THIS GUARANTY.
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Very truly yours,
Kelso Investment Associates VII, L.P.
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Kelso GP VII, L.P., the General Partner
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Kelso GP VII, LLC, its general partner
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/s/ James J. Connors II
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Authorized Officer |
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Accepted and agreed to with
respect to the 2nd, 6th, 9th and 10th paragraphs above, as of the date
first above written: |
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J. Aron & Company
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/s/ Illegible |
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Name: |
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Title: |
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EX-10.3
Exhibit 10.3
FIRST AMENDMENT
TO
AMENDED AND RESTATED
ON-SITE PRODUCT SUPPLY AGREEMENT
This First Amendment to Amended and Restated On-Site Product Supply Agreement (this First
Amendment) is entered into effective as of October 31, 2008 (the First Amendment Effective Date)
by and between Linde, Inc. (formerly known as The BOC Group, Inc.), a Delaware corporation
(hereinafter called Linde), and Coffeyville Resources Nitrogen Fertilizers, LLC, a Delaware
limited liability company (hereinafter called Coffeyville Resources).
Linde and Coffeyville Resources are parties to the Amended and Restated On-Site Product Supply
Agreement dated as of June 1, 2005 (the Agreement), and the parties desire to amend the Agreement
as provided in this First Amendment. Capitalized terms used herein and not otherwise defined shall
have the meanings ascribed to such terms by the Agreement.
The Agreement shall be amended as of the First Amendment Effective Date as set forth below:
1. BOC References. All references to The BOC Group, Inc. and BOC shall be deleted
in each place that they appear in the Agreement and Linde, Inc. and Linde, respectively,
substituted in place thereof.
2. Existing Definitions. Sections 1(c), 1(w) and 1(z) of the Agreement are deleted in
their entirety and replaced with the following:
(c) Linde Facility a plant for the production of Product, Crude Gaseous
Nitrogen and Argon (the Linde Plant), including metering and related facilities,
together with an interconnected liquid Oxygen Product and liquid Nitrogen Product
storage vessels and vaporization equipment (at the Liquid Product Storage
Facility), all connected to the Linde Pipelines and having the production,
delivery, liquid storage and vaporization capabilities or capabilities stated in
Section II and III of Exhibit A hereto, which shall be owned or lease,
maintained and operated by Linde on the Linde Plant Site.
* * *
(w) Nitrogen Product nitrogen gas (including vaporized liquid) and liquid
conforming to the product specifications set forth in Section I of Exhibit A
hereto, but, in all cases, excluding Crude Gaseous Nitrogen.
* * *
(z) Product collectively Oxygen Product, Nitrogen Product, and, after the
Crude Gaseous Nitrogen Facility Completion Date, Crude Gaseous Nitrogen, and, to the
extent provided under this Agreement, CDA Product.
3. New Definitions. Section 1 of the Agreement is amended to add the
following:
(cc) Coffeyville Equipment has the meaning given such term in Section
3(f).
(dd) CDA Supply Termination Date has the meaning given such term in
Section 3(f).
(ee) Gas Nitrogen Effective Date the earlier of (i) the CDA Supply
Termination Date, or (ii) the first anniversary of the completion date of the PPU
Retrofit.
(ff) PPU Retrofit the removal of the existing wire mesh support grid,
followed by installation of a modified perforated plate support system and
replacement of the activated alumina and molecular sieve. The PPU Retrofit will be
deemed to be completed as of the date set forth in a written notice from Linde,
which Linde agrees to provide promptly following completion.
(gg) Crude Gaseous Nitrogen gaseous low pressure, low purity nitrogen
produced as a by-product of the distillation process conforming to the product
specifications set forth in Section I of Exhibit A hereto.
(hh) Crude Gaseous Nitrogen Facility that part of the Linde Plant used for
the distribution of Crude Gaseous Nitrogen.
(ii) Crude Gaseous Nitrogen Facility Completion Date has the meaning given
such term in Section 2(n).
(jj) Neon Electricity has the meaning given such term in Section 4(f).
(kk) Operating Day means hours of operation in any calendar day during
which Linde is providing all Products at the purity, volumes and pressures provided
for herein divided by 24.
(ll) Liquid Production means the sum of liquid Nitrogen Product and liquid
Oxygen Product as determined by Linde scale tickets.
(mm) Lost Liquid Production means Liquid Production which is not realized
by Linde solely due to the supply of High Pressure Air Product by Linde to
Coffeyville Resources pursuant to this Agreement.
4. The Linde Facility and Pipelines. Section 2 of the Agreement is amended to add the
following:
(n) Following the First Amendment Effective Date, Linde shall complete the
necessary engineering and installation of the Crude Gaseous Nitrogen Facility to
supply Crude Gaseous Nitrogen to Coffeyville Resources. Such work will include the
necessary controls, piping, valves, a billing quality flow metering device and
chiller to permit diversion of the Crude Gaseous Nitrogen from the evaporative
cooling unit. Linde will provide piping to the Linde Plant Site limits or a
designated point within the Linde Plant Site. Linde will notify Coffeyville
Resources in writing of the date on which the Crude Gaseous Nitrogen Facility has
been installed (the Crude Gaseous Nitrogen Facility Completion Date).
(o) Following the First Amendment Effective Date, Linde will complete the
necessary engineering and installation to recover Neon gas from the Linde Plant.
This installation will include a billing quality electric meter for determining the
power consumption of this equipment.
5. Purchase and Sale of Product. Section 3 of the Agreement is amended to add the
following:
(e) Following the CDA Supply Termination Date, Linde will discontinue supply
of CDA Product to Coffeyville Resources under the Agreement, except as set forth in
this Section 3(e).
(i) Not more often than two (2) times in any calendar year, upon not
less than ten (10) business days prior written notice from Coffeyville
Resources, Linde shall supply CDA Product, on a temporary basis, from the
Linde Facility for a period of not more than an aggregate of two (2) weeks
in any calendar year, for maintenance on the Coffeyville Equipment. During
such temporary supply of CDA Product, the Production and Delivery
Capabilities of Linde Facility will be in accordance with Section II.E.1 of
Exhibit A. Additionally, during such temporary supply of CDA
Product, the cap for Lost Liquid Production will be $70,000 in any single
month. If Coffeyville Resources requires the temporary supply of CDA
Product for a period greater than two (2) weeks, the cap for Lost Liquid
Production will not be applicable until such temporary supply of CDA Product
is terminated.
(ii) In the event that the Coffeyville Equipment is unable to produce
CDA Product, Coffeyville Resources may request emergency supply of CDA
Product from the Linde Facility. Within the limitations of the existing
operating mode of the Linde Facility at the time such request is made, Linde
shall use reasonable commercial efforts to supply, on an as available basis,
Coffeyville Resources requirements for CDA Product, up to 351,000 scfh of
CDA Product. Within 24 hours of such request for emergency supply of CDA
Product, Linde will adjust the operations of the Linde Facility to provide
Coffeyville Resources requirements for CDA Product, up to 351,000 scfh.
Upon receipt of such emergency request, Product allocation above Level 2 of
the Product Nomination Procedure (Exhibit L) will be suspended while Linde
is supplying CDA Product pursuant to this Section 3(e)(ii). While Linde is
supplying CDA Product pursuant to this Section 3(e)(ii), the cap for Lost
Liquid Production will not be applicable. Lindes obligation to supply CDA
Product pursuant to this Section 3(e)(ii) shall be limited to an aggregate
of ninety (90) days during the term of this Agreement.
(f) Promptly after the Effective Date, Coffeyville Resources shall install
equipment (the Coffeyville Equipment) necessary to supply the Coffeyville
Facilities and the adjacent Refinery with CDA Product. Upon receipt of notice from
Coffeyville Resources that this equipment has been installed and is capable of
supplying CDA Product, Lindes obligation to supply CDA Product under the Agreement
shall terminate, except as set forth in Section 3(e) to the Agreement. The date on
which Linde receives such notice is hereinafter referred to as the CDA Supply
Termination Date.
6. Pricing and Payment. Section 4(e) of the Agreement is deleted in its entirety and
replaced with the following, and a new Section 4(f) is added as follows:
(e) Subject to Section 3(e) and during the Supply Period, Coffeyville
Resources will provide a monthly credit to Linde for Lost Liquid Production. The
credit shall be calculated on a monthly basis using the following formula:
($46/ton)[(OperatingDaysin
Month)(120) (ActualTonsLiquidProduction)]=Credit
and will be capped in any single month as follows:
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$70,000 upon execution of the First
Amendment or during periods of interim CDA Product supply of
Section 3(e). |
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The cap will be reduced by $3,000 upon
completion of the PPU Retrofit. |
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The cap will be reduced by an additional $4,250
upon notification from Coffeyville Resources that their equipment
supplying CDA Product is operational. |
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The cap will be reduced by an additional
$21,750 upon notification by Linde that the Dense Fluid Expander is
operational. |
The $46/ton price and the cap described above will adjust (up or down) on a monthly
basis based upon the actual total power cost as billed to Coffeyville Resources by
the City of Coffeyville, Kansas (expressed as $/KWH) compared to the actual total
power cost in June 2005 (expressed as $/KWH). For the purposes of the cap
adjustment, the appropriate reduction will be taken before making the adjustment.
For example, after the PPU Retrofit, CDA Product removal, and Dense Fluid Expander
installation, the total reduction would be $29,000. The monthly adjustment of the
cap for total power would be made on the new cap of $41,000. The actual total power
cost in June 2005 was $0.03965/KWH. As an example, attached as Exhibit K is
the adjustment calculation per this paragraph for July 2005.
(f) Electricity is required for the operation of the Neon recovery equipment
(the Neon Electricity). Linde will meter the Neon Electricity (subject to the
right of Coffeyville Resources to monitor such meter), and reimburse Coffeyville
Resources monthly based upon the actual total power cost as billed to Coffeyville
Resources by the City of Coffeyville, Kansas (expressed as $/KWH). The Neon
Electricity shall be deducted from the Actual Usage when performing the Excess
Power Calculation (as such terms are used in Exhibit F-3).
7. Argon, CO2 Byproduct and other Byproducts. Section 5(a) of the
Agreement is deleted in its entirety and replaced with the following:
(a) During the Supply Period, Linde shall be entitled to retain, market and
sell for its own account: (i) all Argon produced by the Linde Plant; (ii) all
CO2 Byproduct, except to the extent retained by Coffeyville Resources or
its affiliates and except to the extent otherwise provided in or pursuant to Section
5(b) herein; and (iii) all other byproducts or other industrial gases, in liquid or
gaseous form, including Neon, Krypton, and Xenon, produced by the Linde Plant,
including Product in excess of Lindes obligations to supply same to Coffeyville
Resources hereunder. Linde shall be solely responsible for the proper disposal, in
accordance with all applicable Environmental Laws and Permits of any and all
byproducts and other emissions and waste generated by the Linde Plant (including
from CO2 Byproduct delivered to Linde) other than Products delivered to
Coffeyville Resources hereunder. Except as permitted by Section 5(b) herein,
Coffeyville Resources agrees that it will not sell or deliver CO2
Byproduct to anyone other than Linde, its affiliates and affiliates of Coffeyville
Resources.
8. Product Specifications. Section 7 of the Agreement is amended to add the following
to that section:
If the Crude Gaseous Nitrogen does not conform to the specifications therefor
(Non-Conforming Crude Gaseous Nitrogen), Linde shall notify Coffeyville
Resources promptly by telephone or by such other method as agreed by the Parties
(e.g., by electronic mail) upon discovery of such nonconformance, which notice shall
include (a) the particulars of any nonconformance and (b) the expected duration
thereof, and Linde shall promptly discontinue the supply of Non-Conforming Crude
Gaseous Nitrogen to Coffeyville Resources.
9. Exhibit A.
(a) Section I.A of Exhibit A to the Agreement is amended to add the following:
Crude Gaseous Nitrogen, with inerts: not more than 2% oxygen (with a typical value
of 1.5% oxygen)
(b) Sections II.D and II.E of Exhibit A to the Agreement are deleted in their entirety
and replaced with the following:
D. Gaseous Nitrogen Product (both 500 ± 10 psig and 200 ± 10 psig, but excluding
1300 and 120 psig referred to in Section III.A immediately below):
1. Following the First Amendment Effective Date or during any period when
Linde is temporarily supplying CDA Product pursuant to Section 3(e) of the
Agreement:
1,240,000 scf per hour (maximum instantaneous flow rate at 14.3 psia and
105°F dry bulb and 78°F wet bulb and cooling water at 85°F)
2. As of the Gas Nitrogen Effective Date:
1,260,000 scf per hour (maximum instantaneous flow rate at 14.3 psia and
105°F dry bulb and 78°F wet bulb and cooling water at 85°F)
3. Six (6) months after the Gas Nitrogen Effective Date:
1,280,000 scf per hour (maximum instantaneous flow rate at 14.3 psia and
105°F dry bulb and 78°F wet bulb and cooling water at 85°F)
4. Twenty-four (24) months after the Gas Nitrogen Effective Date:
1,320,000 scf per hour (maximum instantaneous flow rate at 14.3 psia and
105°F dry bulb and 78°F wet bulb and cooling water at 85°F)
E. CDA Product:
1. Prior to installation of the Coffeyville Equipment or, after the CDA
Supply Termination Date, as subsequently requested by Coffeyville Resources
pursuant to Section 3(e) of the Agreement:
351,000 scf per hour (maximum instantaneous flow rate at 14.3 psia and 105°F
dry bulb and 78°F wet bulb and cooling water at 85°F)
2. In the event, prior to the CDA Supply Termination Date, Coffeyville
Resources installs equipment to only partially supply Coffeyville Resources
CDA Product requirements:
115% of the average flow (in scf per hour) over the 120 hours following
notification of partial supply (maximum instantaneous flow rate at 14.3 psia
and 105°F dry bulb and 78°F wet bulb and cooling water at 85°F)
3. Following the CDA Supply Termination Date, except when requested per
Section 3(e) of the Agreement:
0 scf per hour
10. Exhibit B. In Section II of Exhibit B to the Agreement, the definition of
BMPC is deleted in its entirety and replaced with the following:
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BMPC = |
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Base monthly Minimum Product Charge, and each gaseous Product price,
individually, as follows:
$313,885 Base Monthly Minimum Product Charge
$2,000 Crude Gaseous Nitrogen Facility Fee (commencing on the
Crude Gaseous Nitrogen Facility Completion Date)
$0.055 Base Gaseous Oxygen
$0.055 Base Gaseous Nitrogen
$0.019 Base CDA Product |
11. Exhibit G.
(a) Section I of Exhibit G to the Agreement is amended to
add the following:
Notwithstanding any other provisions in the Agreement to the contrary, including
the pricing adjustments described in Exhibit B, the Minimum Product Charge
will increase to the amounts shown below on the indicated dates:
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a. |
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Gas Nitrogen Effective Date $321,915; |
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b. |
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Six months after the Gas Nitrogen Effective Date $329,945; and |
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c. |
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Twenty-four months after the Gas Nitrogen Effective Date $346,005. |
(b) Sections II and III of Exhibit G to the Agreement are deleted in their entirety
and replaced with the following:
II. During the Supply Period, Coffeyville Resources shall pay Linde $0.055 per 100
scf for all quantities of High Pressure gaseous Oxygen Product delivered to
Coffeyville Resources during a calendar month from the output of the Linde Plant, at
total instantaneous flow rates exceeding 1,588,000 scf per hour, and for all
quantities of Low Pressure gaseous Oxygen Product delivered to Coffeyville Resources
during a calendar month from the output of the Linde Plant, at total instantaneous
flow rates exceeding 30,000 scf per hour.
III. During the Supply Period, Coffeyville Resources shall pay Linde $0.055 per 100
scf for all quantities of gaseous Nitrogen Product delivered to Coffeyville
Resources during a calendar month from the output of the Linde Plant, at
instantaneous flow rates exceeding the volume specified in Section II.D of
Exhibit A.
(c) Exhibit G to the Agreement is amended to add the following new Section VII:
VII. During the Supply Period, following the Crude Gaseous Nitrogen Facility
Completion Date, Coffeyville Resources shall pay Linde $2,000 per month as a monthly
minimum product charge for the commitment of the Crude Gaseous Nitrogen Facilities.
Coffeyville Resources shall pay Linde
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$0.021 per 100 scf for all quantities of Crude Gaseous
Nitrogen delivered to Coffeyville Resources during a calendar month
from the output of the Linde Plant up to an aggregate of 13,540,000,000
scf; and |
After a consuming a total of 13,540,000,000 scf of Crude Gaseous Nitrogen,
Coffeyville Resources shall receive a reduction of
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(b) |
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$0.013 per 100 scf to the current price for all
quantities of Crude Gaseous Nitrogen delivered to Coffeyville
Resources. |
11. Exhibit L. Linde and Coffeyville Resources hereby amend the Agreement to add a
new Section 5A as follows:
SECTION 5A PRODUCT NOMINATION PROCEDURE
Linde and Coffeyville hereby agree to allocate Product produced by the Linde
Plant according to the nomination procedure attached to this Agreement as
Exhibit L.
12. Ratify Agreement. Except as otherwise specifically provided to the contrary in
this First Amendment, all of the provisions of the Agreement shall continue in full force and
effect in accordance with their express terms. The Agreement as amended hereby, constitutes the
entire agreement between the parties with respect to the subject matter hereof, and supersedes all
prior or contemporaneous representations, understandings, agreements, communications, or purchase
orders between the parties, whether written or oral, relating to the subject matter hereof.
13. Counterparts. This First Amendment may be executed in any number of counterparts,
each of which will be deemed to be an original, and all of which together will constitute one
instrument. The signature pages to this First Amendment may be exchanged by facsimile.
[signature page follows]
IN WITNESS WHEREOF, the parties have executed this First Amendment as of the First Amendment
Effective Date.
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Linde, Inc. |
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Coffeyville Resources Nitrogen Fertilizers, LLC
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By: |
/s/ Pat Murphy |
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By: |
/s/ Stanley A. Riemann
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Name: Pat Murphy |
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Name: |
Stanley A. Riemann |
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Title: President |
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Title: |
COO |
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EXHIBIT L
PRODUCT NOMINATION PROCEDURE
Production of Product from the Linde Plant shall be allocated using the following Product
Nomination procedure. For ease of presentation, the following terms are defined for use with this
procedure:
HPGO means the High Pressure gaseous Oxygen Product referenced in Section II.A of Exhibit A.
GAN means the gaseous Nitrogen Product referenced in Section II.D of Exhibit A.
LOX means liquid Oxygen Product produced by the Linde Plant
LIN means liquid Nitrogen Product produced by the Linde Plant
For the purposes of this nomination procedure, the following production levels for Product are
defined:
Level 1 Product to Coffeyville Resources
1,588,000 scf per hour of HPGO, and
The scf per hour of GAN as set forth in Section II.D of Exhibit A
Level 2 Product to Linde
The scf per hour of LOX/LIN as follows:
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Upon execution of this First Amendment 60,000 scf per hour |
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Following the CDA Supply Termination Date and subsequent supply of CDA Product off
the Linde Plant is stopped an additional 10,000 scf per hour |
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Upon notification by Linde that the Dense Fluid Expander is operational an
additional 30,000 scf per hour |
When producing LOX/LIN at the 100,000 scf per hour rate of production, no more than 40,000
scf per hour of that production may be as LOX.
Level 3 Product to Coffeyville Resources
Next 50,000 scf per hour of HPGO, and
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Up to 1,683,000 scf per hour of HPGO |
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Subject to the limitations of HPGO production & delivery equipment |
Next 50,000 scf per hour of GAN
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Up to 50,000 scf per hour above the amount specified by Level 1 above |
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Subject to the limitations of GAN compression equipment |
Level 4 Product to Linde (next 60,000 scf per hour of Product produced
Next 60,000 scf per hour of LOX/LIN
Level 5
Any Product production above Level 4
This production may be allocated to either Linde or Coffeyville Resources as agreed in
nomination discussions between the parties
The following guidelines are to be followed when utilizing the nomination procedure.
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The nomination period lasts for two (2) weeks and commences on Monday at noon. |
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Nominations can be reset during the two (2) week period if the Linde Plant experiences
an interruption of operation, or upon the mutual agreement of both parties. |
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All nominations for Product in Level 3, 4 and 5 are if the Linde Plant is then capable
of the listed production levels. |
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Nomination options are made 1 week in advance of the nomination period. |
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Partial nominations within a Level are permitted. |
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For example, Coffeyville Resources can elect to take 20,000 scf per
hour of GAN production as the only nomination in Level 3. That selection would
last for the two (2) week nomination period and any production capacity of the
Linde Plant above that 20,000 scf per hour would be available to Linde under Level
4. |
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Any Product in a Level not being consumed by one party, may be made available, on an
as-available basis, to the other party. |
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For example, due to a full storage condition, Linde has to back down
the LOX/LIN production from 100,000 scf per hour to 20,000 scf per hour. This
80,000 scf per hour of production would be made available to the pipelines until
sufficient room in the liquid storage was available to resume full production. |
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Semi-annually, both parties will examine consumption of nominated Product in Levels 3, 4
and 5 for the prior six (6) month period. If consumption of the nominated Product volumes
is below 35%, and the other party requested a release of the unconsumed volume, but that
release was refused, then the consuming party shall pay for 35% of the nominated Product
volume at the current pricing. |
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To request a release of an unconsumed volume in a nominated Level, the party requesting the
release will submit a notice of that request to the other party. The other party must
respond within 24 hours. Failure to respond will designate a release of the unconsumed
volume. |
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For example, Coffeyville Resources nominates 50,000 scf per hour of
HPGO and 50,000 scf per hour of GAN for Level 3. However, for some reason,
Coffeyville Resources consumption has only been at 20,000 scf per hour of HPGO and
20,000 scf per hour of GAN. Linde can request a release of the 30,000 scf per hour
of HPGO and 30,000 scf per hour of GAN in order to produce LOX/LIN in Level 4. |
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Linde has the nomination rights for Level 5, only during the months of July, August, and
September. Coffeyville Resources has the nomination rights for Level 5 during the
remaining months of the year. |
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Once per year, either party may, with 30 days written notice, elect to deny the other
partys nomination rights above Level 2 for a two (2) week period. This two (2) week
period does not necessarily have to coincide with a normal nomination period and the normal
nomination process will continue in the background. |
EX-10.4
Exhibit 10.4
SECOND AMENDMENT TO
AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT
THIS AMENDMENT TO AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT (this
Amendment), dated as of October 31, 2008, is made between J. Aron & Company, a
general partnership organized under the laws of New York (Supplier) and Coffeyville Resources
Refining & Marketing, LLC, a limited liability company organized under the laws of Delaware
(Coffeyville).
Supplier and Coffeyville are parties to an Amended and Restated Crude Oil Supply Agreement
dated as of December 31, 2007, as amended by the Amendment to Amended and Restated Crude Oil
Supply Agreement dated as of September 26, 2008 (as amended, the Supply Agreement). Coffeyville
and Supplier have agreed to amend certain terms and conditions of the
Supply Agreement.
Accordingly, the Parties hereto agree as follows:
SECTION
1 Definitions; Interpretation.
(a)
Terms Defined in Supply Agreement. All capitalized terms used in this
Amendment (including in the recitals hereof) and not otherwise defined herein have the
meanings assigned to them in the Supply Agreement.
(b) Interpretation. The rules of interpretation set forth in Section 1.2 of the
Supply Agreement apply to this Amendment and are incorporated herein by this reference.
SECTION 2 Amendment to the Supply Agreement.
(a) Amendment. As of the date of this Amendment, the Supply Agreement is amended by deleting the first sentence of Section 3.2 of the Supply Agreement and inserting
the following in place thereof:
Unless either Party has delivered to the other a written notice of its election not
to extend this Agreement pursuant to this Section on or before December 1 of the
calendar year during the then current term, the Expiration Date will, without any
further action, be automatically extended, effective as of the Expiration Date as
then in effect, for an additional one year beyond the Expiration Date as then in
effect (each such period, an Extension Term; and the final day of such
Extension Term becoming the Expiration Date).
(b) References Within Supply Agreement. Each reference in the Supply
Agreement to this Agreement and the words hereof, herein, hereunder, or words of like
import, are a reference to the Supply Agreement as amended by this Amendment.
SECTION 3 Representations and Warranties. To induce the other Party to enter into
this Amendment, each Party hereby (i) confirms and restates, as of the date hereof, the
representations and warranties made by it in Article 16 or any other article or section of the
Supply Agreement and (ii) represents and warrants that no Event of Default or Potential Event of
Default with respect to it has occurred and is continuing.
SECTION 4 Miscellaneous.
(a) Supply Agreement Otherwise Not Affected. Except for the amendments
pursuant hereto, the Supply Agreement remains unchanged. As amended pursuant hereto, the
Supply Agreement remains in full force and effect and is hereby ratified and confirmed in all
respects. The execution and delivery of, or acceptance of, this
Amendment and any other documents and instruments in connection herewith by either Party will not be deemed to
create a course of dealing or otherwise create any express or implied duty by it to provide any other or further amendments, consents or waivers in the future.
(b)
No Reliance. Each Party hereby acknowledges and confirms that it is
executing this Amendment on the basis of its own investigation and for its own reasons without
reliance upon any agreement, representation, understanding or communication by or on behalf of
any other Person.
(c) Costs and Expenses. Each Party is responsible for any costs and expenses incurred by such Party in connection with the negotiation, preparation, execution and
delivery of this Amendment and any other documents to be delivered in connection herewith.
(d) Binding Effect. This Amendment will be binding upon, inure to the
benefit of and be enforceable by Coffeyville, Supplier and their respective successors and
assigns.
(e)
Governing Law. THIS AMENDMENT WILL BE GOVERNED BY,
CONSTRUED AND ENFORCED UNDER THE LAWS OF THE STATE OF NEW YORK
WITHOUT GIVING EFFECT TO ITS CONFLICTS OF LAW PRINCIPLES THAT
WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER STATE.
(f) Amendments. This Amendment may not be modified, amended or otherwise altered except by written instrument executed by the Parties duly authorized representatives.
(g)
Effectiveness; Counterparts. This Amendment will become effective on the date first written above. This Amendment may be executed in any number of counterparts and by different Parties hereto in separate counterparts, each of which when so
executed will be deemed to be an original and all of which taken together constitute but one and the same agreement.
(h) Interpretation. This Amendment is the result of negotiations between and have
been reviewed by counsel to each of the Parties, and is the product of all Parties hereto.
Accordingly, this Amendment will not be construed against either Party merely because of such
Partys involvement in the preparation hereof.
2
The Parties hereto have duly executed this Amendment, as of the date first above written.
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J. ARON & COMPANY
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By: |
/s/ Andre Eriksson
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Name: |
Andre Eriksson |
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Title: |
Managing Director |
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COFFEYVILLE RESOURCES REFINING &
MARKETING, LLC
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By: |
/s/ John J. Lipinski
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Name: |
John J. Lipinski |
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Title: |
CEO |
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3
EX-31.1
Exhibit 31.1
CERTIFICATION
I, John J. Lipinski, certify that:
1. I have reviewed this Quarterly Report on
Form 10-Q
of CVR Energy, Inc.;
2. Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and
other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrants other certifying officer and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e))
for the registrant and have:
a) Designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b) Evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
c) Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably
likely to materially affect, the registrants internal
control over financial reporting; and
5. The registrants other certifying officer and I
have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrants
auditors and the audit committee of the registrants board
of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in
the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
John J. Lipinski
Chief Executive Officer
Date: November 13, 2008
EX-31.2
Exhibit 31.2
CERTIFICATION
I, James T. Rens, certify that:
1. I have reviewed this Quarterly Report on
Form 10-Q
of CVR Energy, Inc.;
2. Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and
other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrants other certifying officer and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e))
for the registrant and have:
a) Designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b) Evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
c) Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably
likely to materially affect, the registrants internal
control over financial reporting; and
5. The registrants other certifying officer and I
have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrants
auditors and the audit committee of the registrants board
of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in
the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
James T. Rens
Chief Financial Officer
Date: November 13, 2008
EX-32.1
Exhibit 32.1
CERTIFICATION
PURSUANT TO 18 U.S.C. §1350,
AS ADOPTED PURSUANT TO §906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the filing of the Quarterly Report on
Form 10-Q
of CVR Energy, Inc., a Delaware corporation (the
Company), for the period ended September 30,
2008, as filed with the Securities and Exchange Commission on
the date hereof (the Report), each of the
undersigned officers of the Company certifies, pursuant to
18 U.S.C. § 1350, as adopted pursuant to
§ 906 of the Sarbanes-Oxley Act of 2002, that, to such
officers knowledge:
(1) The Report fully complies with the requirements of
Section 13(a) or 15(d) of the Securities Exchange Act of
1934; and
(2) The information contained in the Report fairly
presents, in all material respects, the financial condition and
results of operations of the Company as of the dates and for the
periods expressed in the Report.
John J. Lipinski
Chief Executive Officer
James T. Rens
Chief Financial Officer
Date: November 13, 2008
EX-99.1
Exhibit 99.1
RISK FACTORS
You should carefully consider each of the following risks together with the other information
contained in this Report and all of the information set forth in our filings with the SEC. 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.
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.
If we are required to obtain our crude oil supply without the benefit of a crude oil
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 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. The current credit intermediation agreement with J. Aron expires
on December 31, 2008 and will not be extended beyond February 15, 2009. We are discussing a new
crude oil intermediation agreement with multiple alternative parties. However, there can be no
assurance that we will be able to enter into a new agreement before the expiration of our agreement
with J. Aron or that we will be able to obtain similar services from another party on similar terms
or at all. Further, if we are 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, 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 September 30, 2008, we had cash, cash equivalents and short-term investments of
$59.9 million and $115.1 million available under our revolving credit facility. As of November 6,
2008, we had cash, cash equivalents and short-term investments of $54.3 million and up to $115.1
million available under our revolving credit facility. In the current volatile crude oil
environment, working capital is subject to substantial variability from week-to-week and
month-to-month.
We have 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 the first three quarters of 2008 we experienced extremely high oil prices which
substantially increased our short-term working capital needs. Although oil prices have fallen in
recent weeks, they remain extremely volatile, and our short-term working capital needs may
dramatically increase at any time. 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 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 $41 million per year over five years. We also
have significant short-term and long-term needs for cash, including deferred payments of $62.7
million at November 6, 2008 (plus accrued interest) that are owed under the Cash Flow Swap with J.
Aron.
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.
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.
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.
From time to time we install new equipment and redesign older equipment to improve refinery
capacity. The installation and redesign of key equipment involves significant risks and
uncertainties, including the following:
our upgraded equipment may not perform at expected throughput levels;
the yield and product quality of new equipment may differ from design; and
redesign or modification of the equipment may be required to correct equipment that does not
perform as expected, which could require facility shutdowns until the equipment has been
redesigned or modified.
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.
2
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.
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 $51 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.
3
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
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 $85 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.
4
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. Natural gas prices have been high for much of 2008, resulting in historically
high nitrogen fertilizer prices. 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 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.
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.
5
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 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 customers, suffer lower margins, and experience other material
adverse effects to its results of operations, financial condition and ability to make cash
distributions.
6
The nitrogen fertilizer business relies on an air separation plant owned by Linde, Inc. to
provide oxygen, nitrogen and compressed dry air to its gasifier. A deterioration in the financial
condition of Linde, Inc., 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 Linde, Inc., 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.
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 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, or
the City, for the supply of electricity. The contract with Linde extends through 2020 and the
electricity contract with the City 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.
7
Following
a period of discussions with the City and in light of the Citys
contention that we had constructively terminated the contract, we have filed a lawsuit against the City to have
the contract enforced as written and to recover other damages. The electricity contract specifies the price we pay for electricity. The City has recently
begun to charge us a higher rate for electricity. Even if the City is successful in
the lawsuit, it is required under Kansas law to continue to supply us
with power. However, it would
be able to charge us a higher rate for electricity.
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.
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.
8
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.
Risks Related to Our Entire Business
Unprecedented instability and volatility in the capital and credit markets could have a
negative impact on our business, financial condition, results of operations and cash flows.
The capital and credit markets have been experiencing extreme volatility and disruption. In
recent weeks, the volatility and disruption have reached unprecedented levels. Our business,
financial condition and results of operations could be negatively impacted by the difficult
conditions and extreme volatility in the capital, credit and commodities markets and in the global
economy. These factors, combined with volatile oil prices, declining business and consumer
confidence and increased unemployment, have precipitated an economic slowdown and fears of a
recession. The difficult conditions in these markets and the overall economy affect us in a number
of ways. For example:
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Although we believe we have sufficient liquidity under our revolving credit facility
to run our business, under extreme market conditions there can be no assurance that
such funds would be available or sufficient, and in such a case, we may not be able to
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Recent market volatility has exerted downward pressure on our stock price, which may
make it more difficult for us to raise additional capital and thereby limit our ability
to grow. |
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Market conditions could result in our significant customers experiencing financial
difficulties. We are exposed to the credit risk of our customers, and their failure to
meet their financial obligations when due because of bankruptcy, lack of liquidity,
operational failure or other reasons could result in decreased sales and earnings for
us. |
The turmoil in the global economy may also impact our business, financial condition and
results of operations in ways we cannot currently predict. We do not know if market conditions or
the state of the overall economy will improve in the near future.
9
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
$1.0 billion which is subject to various deductibles and sub-limits for particular types of
coverage (e.g., $200 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.
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. 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
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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 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 57% and 14% of crude oil capacity for the periods October
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, at which time the unrealized loss will become a fixed obligation.
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 Risks
Related to Our Petroleum Business Our internally generated cash flows and other sources of
liquidity may not be adequate for our capital needs above.
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 $69.1 million for the years ended December
31, 2006 and 2007 and the nine months ended September 30, 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 September 30, 2008, a $1.00 change in quoted prices for the
absolute crack spreads utilized in the Cash Flow Swap would result in a $23.9 million change to the
fair value of derivative commodity position and the same change to net income.
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.
As of September 30, 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 $154.6 million. Total
anticipated insurance recoveries of approximately $104.2 million have been recorded as of September
30, 2008 (of which $49.5 million had already been received from insurance carriers by us as of that
date), resulting in a net cost of approximately $50.4 million. Subsequent to September 30, 2008,
we received an additional $9.8 million from our property insurance carriers. 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.
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 September 30, 2008 related to the third party costs to repair the refinery and
fertilizer facilities were approximately $77.0 million and $4.4 million, respectively.
Additionally, other corporate overhead and miscellaneous costs incurred and recorded in connection
with the flood as of September 30, 2008 were approximately $20.4 million. 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 substantially completed remediation of the contamination caused by the crude oil
discharge by July 2008 and expect any remaining minor remedial actions to be completed by December
31, 2008. As of September 30, 2008, the
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total gross costs recorded associated with remediation and third party property damage as of
the result of the crude oil discharge for obligations approximated $52.8 million.
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.
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 filed two lawsuits against certain of our insurance carriers on July 10, 2008 relating
to disagreements regarding the amounts we are entitled to recover for flood-related property and
environmental damage. 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.
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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 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.
CO2 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 U.S. Congress has considered various proposals to reduce greenhouse gas emissions, but
none have become law, and presently, there are no federal mandatory requirements to reduce
greenhouse gas emissions. While it is probable that Congress will adopt some form of federal cap
and trade program to reduce greenhouse gas emissions in the future, the timing and specific
requirements of any such legislation are uncertain at this time. In the absence of existing federal
regulations, a number of states have adopted regional greenhouse gas initiatives to reduce CO2
and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas
(where our refinery and the nitrogen fertilizer facility are located) formed the Midwestern
Greenhouse Gas Accord, which calls for the development of 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.
Even in the absence of federal or state legislation, regulatory restrictions on greenhouse gas
emissions may be imposed. In 2007, in Massachusetts v. EPA., the U.S. Supreme Court decided that
CO2 may be regulated as an air pollutant under the federal Clean Air Act for the purpose
of vehicle emissions. Similar lawsuits have been filed seeking to require the EPA to regulate
CO2 emissions from stationary sources, such as our refinery and the fertilizer plant,
under the federal Clean Air Act. In response to the U.S. Supreme Courts decision in Massachusetts
v. EPA, in July 2008 the EPA released an Advanced Notice of Proposed Rulemaking with respect to
possible future regulation of greenhouse gas emissions under the federal Clean Air Act. Our
refinery and the nitrogen fertilizer plant produce significant amounts of CO2 that are
vented into the atmosphere. If the EPA regulates CO2 emissions from facilities such as
ours, we may have to apply for additional permits, install additional controls to reduce CO2
emissions or take other as yet unknown steps to comply with these potential regulations. For
example, we may have to purchase CO2 emission reduction credits to reduce our current
emissions of CO2 or to offset increases in CO2 emissions associated with
expansions of our operations.
13
Compliance with any future legislation or regulation of greenhouse gas emissions 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.
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 an
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 managing general partner of 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 41.4% of our
petroleum sales for the years ended December 31, 2006 and 2007 and the nine months ended September
30, 2008, respectively. Further, in the aggregate, the top five ammonia customers of the nitrogen
fertilizer business represented 51.9%, 62.1% and 63.1% of its ammonia sales for the years ended
December 31, 2006 and 2007 and the nine months ended September 30, 2008, respectively, and the top
five UAN customers of the nitrogen fertilizer business represented 30.0%, 38.7% and 33.2% 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.
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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 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. The
nitrogen facility completed a scheduled turnaround in October 2008. The next scheduled turnaround
of the nitrogen fertilizer facility will be in 2010.
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:
unforeseen difficulties in the acquired operations and disruption of the ongoing operations of
our petroleum business and the nitrogen fertilizer business;
failure to achieve cost savings or other financial or operating objectives with respect to an
acquisition;
strain on the operational and managerial controls and procedures of our petroleum business and
the nitrogen fertilizer business, and the need to modify systems or to add management resources;
difficulties in the integration and retention of customers or personnel and the integration and
effective deployment of operations or technologies;
assumption of unknown material liabilities or regulatory non-compliance issues;
amortization of acquired assets, which would reduce future reported earnings;
possible adverse short-term effects on our cash flows or operating results; and
diversion of managements attention from the ongoing operations of our business.
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 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 Limited Partnership Structure Through Which We Hold Our Interest in the
15
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 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 September 30, 2008, we had total debt outstanding of $500.6 million, $34.9 million in
funded letters of credit outstanding and borrowing availability of $115.1 million under our credit
facility. 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:
limiting our ability to obtain additional financing to fund our working capital,
acquisitions, expenditures, debt service requirements or for other purposes;
limiting our ability to use operating cash flow in other areas of our business because we
must dedicate a substantial portion of these funds to service debt;
limiting our ability to compete with other companies who are not as highly leveraged;
placing restrictive financial and operating covenants in the agreements governing our and
our subsidiaries long-term indebtedness and bank loans, including, in the case of certain
indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay
dividends or make other distributions to us;
exposing us to potential events of default (if not cured or waived) under financial and
operating covenants contained in our or our subsidiaries debt instruments that could have a
material adverse effect on our business, financial condition and operating results;
increasing our vulnerability to a downturn in general economic conditions or in pricing of
our products; and
limiting our ability to react to changing market conditions in our industry and in our
customers industries.
In addition, borrowings under our existing credit facility 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 September 30, 2008, would
correspondingly change our interest expense by approximately $4.9 million per year.
If our credit ratings decline in the future, the interest rates we are charged on debt under
our 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, 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. 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 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.
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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
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 September 30, 2008, approximately 39% of our employees, all of whom work in our
petroleum business, were represented by labor unions under collective bargaining agreements. We
have recently reached a new agreement with the 6 unions of the Metal Trades Department of the
AFL-CIO, which will now expire in March 2013. Our current agreement with the United Steelworkers
of America is scheduled to expire in March 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
17
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 has been
actively engaged in the planning for, design, and implementation of remediation efforts to enhance
controls to ensure the proper accounting for the calculation of the cost of crude oil. As a result
of the plan and development of the initiatives to remediate the material weaknesses, we have
centralized all crude oil cost accounting functions and have added additional layers of accounting
review with respect to our crude oil cost accounting. Also, additional layers of business review
in conjunction with the accounting review of the computation of our crude oil costs have been
added. As of September 30, 2008, the material weaknesses have not been fully remediated as the
testing of the controls that have been put in place has not been completed.
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:
the requirement that a majority of our board of directors consist of independent directors;
the requirement that we have a nominating/corporate governance committee that is composed
entirely of independent directors with a written charter addressing the committees purpose and
responsibilities; and
the requirement that we have a compensation committee that is composed entirely of independent
directors with a written charter addressing the committees purpose and responsibilities.
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We are relying on all of these exemptions as a controlled company, except that our
nominating/corporate governance and compensation committees do have written charters. 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.
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:
the failure of securities analysts to cover our common stock or changes in financial
estimates by analysts;
announcements by us or our competitors regarding, among other things, significant contracts
or acquisitions;
variations in our quarterly results of operations;
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loss of a large customer or supplier;
general economic conditions;
terrorist acts;
future sales of our common stock; and
investor perceptions of us and the industries in which our products are used.
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.
The Goldman Sachs Funds and the Kelso Funds 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.
As of the date of this Report, each of the Goldman Sachs Funds and the Kelso Funds controls
36.5% of our outstanding common stock (together, they control 73% of our outstanding common stock).
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 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. 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 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.
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
20
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 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.
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
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. 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 $3.3 million, assuming all of the shares
of our common stock held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were
sold at $3.97 per share, which was the closing price of our common stock on October 31, 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. We entered into a letter agreement with J.
Aron on October 11, 2008 to defer to July 31, 2009 the outstanding balance under the Cash Flow Swap
of $72.5 million plus accrued interest. The guarantee provided by one of the Goldman Sachs Funds
and one of the Kelso Funds will remain in effect until the expiration of this new deferral. 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.
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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 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.
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 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.
22
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
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.
23
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 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:
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.
Fertilizer GP may also have an incentive to engage in conduct with a high degree of risk in
order to increase cash flows substantially and thereby increase the value of the IDRs instead of
following a safer course of action.
The owners of Fertilizer GP, who are also our controlling stockholders and senior management,
are permitted to compete with us or the Partnership or to own businesses that compete with us or
the Partnership. In addition, the owners of Fertilizer GP are not required to share business
opportunities with us, and our owners are not required to share business opportunities with the
Partnership or Fertilizer GP.
Neither the partnership agreement nor any other agreement requires the owners of Fertilizer GP
to pursue a business strategy that favors us or the Partnership. The owners of Fertilizer GP have
fiduciary duties to make decisions in their own best interests, which may be contrary to our
interests and the interests of the Partnership. In addition, Fertilizer GP is allowed to take
into account the interests of parties other than us, such as its owners, or the Partnership in
resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.
Fertilizer GP has limited its liability and reduced its fiduciary duties under the partnership
agreement and has also restricted the remedies available to the unitholders of the Partnership,
including us, for actions that, without the limitations, might constitute breaches of fiduciary
duty. As a result of our ownership interest in the Partnership, we may consent to some actions
and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties
under applicable state law.
Fertilizer GP determines the amount and timing of asset purchases and sales, capital
expenditures, borrowings, repayment of indebtedness, issuances of additional partnership
interests and cash reserves maintained by the Partnership (subject to our specified joint
management rights), each of which can affect the amount of cash that is available for
distribution to us in our capacity as a holder of special units and the amount of cash paid to
Fertilizer GP in respect of its IDRs.
24
Fertilizer GP will also able to determine the amount and timing of any capital expenditures and
whether a capital expenditure is for maintenance, which reduces operating surplus, or expansion,
which does not. Such determinations can affect the amount of cash that is available for
distribution and the manner in which the cash is distributed.
In some instances Fertilizer GP may cause the Partnership to borrow funds in order to permit
the payment of cash distributions, even if the purpose or effect of the borrowing is to make
incentive distributions, which may not be in our interests.
The partnership agreement permits the Partnership to classify up to $60 million as operating
surplus, even if this cash is generated from asset sales, borrowings other than working capital
borrowings or other sources the distribution of which would otherwise constitute capital surplus.
This cash may be used to fund distributions in respect of the IDRs.
The partnership agreement does not restrict Fertilizer GP from causing the nitrogen fertilizer
business to pay it or its affiliates for any services rendered to the Partnership or entering
into additional contractual arrangements with any of these entities on behalf of the Partnership.
Fertilizer GP may exercise its rights to call and purchase all of the 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.
Fertilizer GP controls the enforcement of obligations owed to the Partnership by it and its
affiliates. In addition, Fertilizer GP decides whether to retain separate counsel or others to
perform services for the Partnership.
Fertilizer GP determines which costs incurred by it and its affiliates are reimbursable by the
Partnership.
The executive officers of Fertilizer GP, and the majority of the directors of Fertilizer GP,
also serve as our 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.
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:
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, us or our affiliates. Decisions made
by Fertilizer GP in its individual capacity will be made by the sole member of Fertilizer GP, and
not by the board of directors of Fertilizer GP. Examples include the exercise of its limited call
right, its voting rights, its registration rights and its determination whether or not to consent
to any merger or consolidation or amendment to the partnership agreement.
The partnership agreement provides that Fertilizer GP will not have any liability to the
Partnership or to us for decisions made in its capacity as managing general partner so long as it
acted in good faith, meaning it believed that the decisions were in the best interests of the
Partnership.
The partnership agreement provides that Fertilizer GP and its officers and directors will not
be liable for monetary damages to the Partnership for any acts or omissions unless there has been
a final and non-appealable judgment entered by a court of competent jurisdiction determining that
Fertilizer GP or those persons acted in bad faith or engaged in fraud or willful misconduct, or
in the case of a criminal matter, acted with knowledge that such persons conduct was criminal.
The partnership agreement generally provides that affiliate transactions and resolutions of
conflicts of interest not approved by the conflicts committee of the board of directors of
Fertilizer GP and not involving a vote of unitholders must be on terms no less favorable to the
Partnership than those generally provided to or available from unrelated third parties or be
fair and reasonable. In determining whether a transaction or resolution is fair and
reasonable, Fertilizer GP may consider the totality of the relationship between the parties
involved, including other transactions that may be particularly advantageous or beneficial to the
Partnership.
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The 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.
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 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
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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 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 domestic production of nitrogen fertilizer products by others,
the extent of government regulation and overall economic and local market conditions. In addition:
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.
Although the partnership agreement requires the nitrogen fertilizer business to distribute its
available cash, the partnership agreement may be amended.
Any credit facility that the nitrogen fertilizer business enters into may limit the
distributions which the nitrogen fertilizer business can make. In addition, any credit facility
may contain financial tests and covenants that the nitrogen fertilizer business must satisfy. Any
failure to comply with these tests and covenants could result in the lenders prohibiting
distributions by the nitrogen fertilizer business.
The actual amount of cash available for distribution will depend on numerous factors, some of
which are beyond the control of the nitrogen fertilizer business, including the level of capital
expenditures made by the nitrogen fertilizer business, the nitrogen fertilizer business debt
service requirements, the cost of acquisitions, if any, fluctuations in its working capital
needs, its ability to borrow funds and access capital markets, the amount of fees and expenses
incurred by the nitrogen fertilizer business, and restrictions on distributions and on the
ability of the nitrogen fertilizer business to make working capital and other borrowings for
distributions contained in its credit agreements.
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 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.
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 collectively beneficially own approximately 73% of our
common stock. 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 on the ability of the
current owners of Fertilizer GP to transfer their
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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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