FORM 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, 2007
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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
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61-1512186
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(State or other jurisdiction
of
incorporation or organization)
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(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. (1) Yes þ No o. (2) Yes
o No þ.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer (as defined in
Rule 12b-2
of the Exchange Act).
Large accelerated
filer o Accelerated
Filer o Non-accelerated
Filer þ
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 86,141,291 shares of the registrants
Common Stock outstanding at December 4, 2007.
CVR
ENERGY, INC. AND SUBSIDIARIES
INDEX TO
QUARTERLY REPORT ON
FORM 10-Q
For The
Quarter Ended September 30, 2007
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
CONSOLIDATED BALANCE SHEETS
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Pro Forma
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December 31,
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September 30,
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September 30,
|
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2006
|
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2007
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2007
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(Note 2)
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(Unaudited)
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ASSETS
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Current Assets:
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|
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Cash and cash equivalents
|
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$
|
41,919,260
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$
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27,318,206
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$
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65,117,537
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Accounts receivable, net of allowance for doubtful accounts of
$375,443 and $387,078, respectively
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69,589,161
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65,416,983
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65,416,983
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Inventories
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161,432,793
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209,852,915
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209,852,915
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Prepaid expenses and other current assets
|
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18,524,017
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28,189,488
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19,023,406
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Insurance receivable
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84,982,065
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84,982,065
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Income tax receivable
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32,099,163
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60,937,101
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60,937,101
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Deferred income taxes
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18,888,660
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99,559,780
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99,559,780
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Total current assets
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342,453,054
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576,256,538
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604,889,787
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Property, plant, and equipment, net of accumulated depreciation
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1,007,155,873
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1,164,047,449
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1,164,633,272
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Intangible assets, net
|
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638,456
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497,193
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497,193
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Goodwill
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83,774,885
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83,774,885
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83,774,885
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Deferred financing costs, net
|
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9,128,258
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8,012,476
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6,720,298
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Insurance receivable
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11,400,000
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11,400,000
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Other long-term assets
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6,328,989
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4,579,226
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4,579,226
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Total assets
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$
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1,449,479,515
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$
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1,848,567,767
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$
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1,876,494,661
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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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5,797,981
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$
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57,682,429
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$
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4,906,842
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Revolving debt
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20,000,000
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Note Payable
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5,947,031
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5,947,031
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Payable to swap counterparty
|
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36,894,802
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241,427,327
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241,427,327
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Accounts payable
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138,911,088
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189,713,780
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187,157,412
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Personnel accruals
|
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24,731,283
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31,534,879
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31,534,879
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Accrued taxes other than income taxes
|
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|
9,034,841
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9,648,199
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9,648,199
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Deferred revenue
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8,812,350
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6,747,733
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6,747,733
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Other current liabilities
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6,017,435
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40,550,215
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34,611,451
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Total current liabilities
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230,199,780
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603,251,593
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521,980,874
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Long-term liabilities:
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Long-term debt, less current portion
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769,202,019
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763,447,415
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486,223,002
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Accrued environmental liabilities
|
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5,395,105
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|
|
|
5,603,884
|
|
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5,603,884
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Deferred income taxes
|
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|
284,122,958
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|
|
328,785,428
|
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|
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328,785,428
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Payable to swap counterparty
|
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|
72,806,486
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99,202,285
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99,202,285
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Total long-term liabilities
|
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1,131,526,568
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1,197,039,012
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|
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919,814,599
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Commitments and contingencies
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Minority interest in subsidiaries
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|
4,326,188
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|
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5,169,375
|
|
|
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10,600,000
|
|
Management voting common units subject to redemption,
201,063 units issued and outstanding in 2006 and 2007,
respectively
|
|
|
6,980,907
|
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|
|
8,655,762
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Members equity:
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Voting common units, 22,614,937 units issued and
outstanding in 2006 and 2007, respectively
|
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73,593,326
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29,956,946
|
|
|
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|
|
Management nonvoting override units, 2,976,353 units issued
and outstanding in 2006 and 2007, respectively
|
|
|
2,852,746
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|
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4,495,079
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Total members equity
|
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|
76,446,072
|
|
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|
34,452,025
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PRO FORMA STOCKHOLDERS EQUITY
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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
|
|
|
|
|
|
|
|
|
|
|
861,413
|
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Additional paid-in capital
|
|
|
|
|
|
|
|
|
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434,529,953
|
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Retained earnings
|
|
|
|
|
|
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|
|
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(11,292,178
|
)
|
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Total pro forma stockholders equity
|
|
|
|
|
|
|
|
|
|
|
424,099,188
|
|
Total liabilities and equity
|
|
$
|
1,449,479,515
|
|
|
$
|
1,848,567,767
|
|
|
$
|
1,876,494,661
|
|
|
|
|
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The accompanying notes are an integral part of the condensed
consolidated financial statements.
2
CVR
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
Net sales
|
|
$
|
778,586,242
|
|
|
$
|
585,977,758
|
|
|
$
|
2,329,152,871
|
|
|
$
|
1,819,873,670
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
644,627,352
|
|
|
|
446,169,603
|
|
|
|
1,848,076,557
|
|
|
|
1,319,462,926
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
56,695,517
|
|
|
|
44,440,204
|
|
|
|
144,461,227
|
|
|
|
218,806,288
|
|
Selling, general and administrative expenses (exclusive of
depreciation and amortization)
|
|
|
12,326,943
|
|
|
|
14,034,765
|
|
|
|
32,796,414
|
|
|
|
42,122,058
|
|
Net costs associated with flood
|
|
|
|
|
|
|
32,192,342
|
|
|
|
|
|
|
|
34,331,284
|
|
Depreciation and amortization
|
|
|
12,787,536
|
|
|
|
10,481,065
|
|
|
|
36,809,644
|
|
|
|
42,673,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
726,437,348
|
|
|
|
547,317,979
|
|
|
|
2,062,143,842
|
|
|
|
1,657,396,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
52,148,894
|
|
|
|
38,659,779
|
|
|
|
267,009,029
|
|
|
|
162,477,591
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other financing costs
|
|
|
(10,681,064
|
)
|
|
|
(18,339,731
|
)
|
|
|
(33,016,684
|
)
|
|
|
(45,959,154
|
)
|
Interest income
|
|
|
1,090,792
|
|
|
|
150,610
|
|
|
|
2,773,949
|
|
|
|
763,926
|
|
Gain (Loss) on derivatives
|
|
|
171,208,895
|
|
|
|
40,532,495
|
|
|
|
44,746,853
|
|
|
|
(251,911,939
|
)
|
Other income (expense)
|
|
|
573,569
|
|
|
|
52,393
|
|
|
|
310,704
|
|
|
|
154,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
162,192,192
|
|
|
|
22,395,767
|
|
|
|
14,814,822
|
|
|
|
(296,952,540
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
|
214,341,086
|
|
|
|
61,055,546
|
|
|
|
281,823,851
|
|
|
|
(134,474,949
|
)
|
Income tax expense (benefit)
|
|
|
85,302,273
|
|
|
|
47,609,671
|
|
|
|
111,027,829
|
|
|
|
(93,356,611
|
)
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
(46,686
|
)
|
|
|
|
|
|
|
210,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
129,038,813
|
|
|
$
|
13,399,189
|
|
|
$
|
170,796,022
|
|
|
$
|
(40,908,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Information (Note 2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
Diluted earnings (loss) per common share
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
Basic weighted average common shares outstanding
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Diluted weighted average common shares outstanding
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
3
CVR
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
170,796,022
|
|
|
$
|
(40,908,276
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
36,809,644
|
|
|
|
50,300,595
|
|
Provision for doubtful accounts
|
|
|
2,664
|
|
|
|
11,635
|
|
Amortization of deferred financing costs
|
|
|
2,508,847
|
|
|
|
1,946,912
|
|
Loss on disposition of fixed assets
|
|
|
1,188,360
|
|
|
|
1,245,656
|
|
Forgiveness of note receivable
|
|
|
350,000
|
|
|
|
|
|
Share-based compensation
|
|
|
1,373,624
|
|
|
|
1,642,333
|
|
Minority interest in loss of subsidiaries
|
|
|
|
|
|
|
(210,062
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
23,149,463
|
|
|
|
4,160,543
|
|
Inventories
|
|
|
(59,782,643
|
)
|
|
|
(48,420,122
|
)
|
Prepaid expenses and other current assets
|
|
|
(16,537,977
|
)
|
|
|
(2,024,037
|
)
|
Insurance receivable
|
|
|
|
|
|
|
(96,382,065
|
)
|
Other long-term assets
|
|
|
1,081,470
|
|
|
|
1,592,398
|
|
Accounts payable
|
|
|
(380,356
|
)
|
|
|
82,358,374
|
|
Accrued income taxes
|
|
|
(16,725,901
|
)
|
|
|
(28,837,938
|
)
|
Deferred revenue
|
|
|
(6,664,314
|
)
|
|
|
(2,064,617
|
)
|
Other current liabilities
|
|
|
(7,071,516
|
)
|
|
|
41,949,735
|
|
Payable to swap counterparty
|
|
|
(88,458,131
|
)
|
|
|
230,928,324
|
|
Accrued environmental liabilities
|
|
|
(1,380,841
|
)
|
|
|
208,779
|
|
Deferred income taxes
|
|
|
57,603,030
|
|
|
|
(36,008,650
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
97,861,445
|
|
|
|
161,489,517
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(172,950,391
|
)
|
|
|
(239,694,882
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(172,950,391
|
)
|
|
|
(239,694,882
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Revolving debt payments
|
|
|
|
|
|
|
(241,800,000
|
)
|
Revolving debt borrowings
|
|
|
|
|
|
|
261,800,000
|
|
Proceeds from issuance of term debt
|
|
|
30,000,000
|
|
|
|
50,000,000
|
|
Principal payments on long-term debt
|
|
|
(1,679,076
|
)
|
|
|
(3,870,156
|
)
|
Payment of financing costs
|
|
|
|
|
|
|
(2,525,533
|
)
|
Issuance of members equity
|
|
|
20,000,000
|
|
|
|
|
|
Payment of note receivable
|
|
|
150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
48,470,924
|
|
|
|
63,604,311
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(26,618,022
|
)
|
|
|
(14,601,054
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
64,703,524
|
|
|
|
41,919,260
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
38,085,502
|
|
|
$
|
27,318,206
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
|
Cash paid for income taxes, net of refunds (received)
|
|
$
|
70,150,700
|
|
|
$
|
(28,510,023
|
)
|
Cash paid for interest
|
|
$
|
38,229,085
|
|
|
$
|
37,363,134
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
Accrual of construction in progress additions
|
|
$
|
20,195,007
|
|
|
$
|
(31,555,682
|
)
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
4
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2007
(UNAUDITED)
|
|
(1)
|
Organization,
Initial Public Offering, 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 prior to October 16, 2007 (the date of the
restructuring as further discussed in this note) and subsequent
to June 24, 2005 are to Coffeyville Acquisition LLC (CALLC)
and its subsidiaries.
On June 24, 2005, CALLC acquired all of the outstanding
stock of Coffeyville Refining & Marketing, Inc. (CRM);
Coffeyville Nitrogen Fertilizers, Inc. (CNF); Coffeyville Crude
Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and
Coffeyville Terminal, Inc. (CT) (collectively, CRIncs). CRIncs
collectively own 100% of CL JV Holdings, LLC (CLJV) and,
directly or through CLJV, they collectively own 100% of
Coffeyville Resources, LLC (CRLLC) and its wholly owned
subsidiaries, Coffeyville Resources Refining &
Marketing, LLC (CRRM); Coffeyville Resources Nitrogen
Fertilizers, LLC (CRNF); Coffeyville Resources Crude
Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC
(CRP); and Coffeyville Resources Terminal, LLC (CRT).
The Company, through its wholly-owned subsidiaries, acts as an
independent petroleum refiner and marketer in the
mid-continental United States and a producer and marketer of
upgraded nitrogen fertilizer products in North America. The
Companys operations include two business segments: the
petroleum segment and the nitrogen fertilizer segment. See
Note 15 (Business Segments) for a further
discussion of the companys business segments.
CALLC formed CVR Energy, Inc. (CVR) as a wholly owned
subsidiary, incorporated in Delaware in September 2006, in order
to effect an initial public offering. CALLC formed Coffeyville
Refining & Marketing Holdings, Inc. (Refining Holdco)
as a wholly owned subsidiary, incorporated in Delaware in August
2007, by contributing its shares of CRM to Refining Holdco in
exchange for its shares. Refining Holdco was formed in
connection with a financing transaction in August 2007. The
initial public offering of CVR was consummated on
October 26, 2007. In conjunction with the initial public
offering, a restructuring occurred in which CVR became a direct
or indirect owner of all of the subsidiaries of CALLC.
Additionally, in connection with the initial public offering,
CALLC was split into two entities: Coffeyville Acquisition LLC
and Coffeyville Acquisition II LLC (CALLC II).
Initial
Public Offering of CVR Energy, Inc.
On October 26, 2007, CVR Energy, Inc. completed an initial
public offering of 23,000,000 shares of its common stock.
The initial public offering price was $19.00 per share.
The net proceeds to CVR from the initial public offering were
approximately $408.5 million, after deducting underwriting
discounts and commissions, but before deduction of offering
expenses. The Company also incurred approximately
$11.4 million of other costs related to the initial public
offering. The net proceeds from this offering were used to repay
$280 million of term debt under the Companys credit
facility and to repay all indebtedness under the Companys
$25 million unsecured facility and $25 million secured
facility, including related accrued interest through the date of
repayment of approximately $5.9 million. Additionally,
$50 million of net proceeds were used to repay outstanding
indebtedness under the revolving loan facility under the
Companys credit facility. In connection with the repayment
of the $25 million unsecured facility and the
$25 million secured facility, the Company will record a
write-off of unamortized deferred financing fees of
approximately $1.3 million in the fourth quarter of 2007.
In connection with the initial public offering, CVR became the
indirect owner of the subsidiaries of CALLC and CALLC II. This
was accomplished by CVR issuing 62,866,720 shares of its
common stock to CALLC and CALLC II, its majority stockholders,
in conjunction with the mergers of two newly formed direct
subsidiaries of
5
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
CVR into Refining Holdco and CNF. Concurrent with the merger of
the subsidiaries and in accordance with a previously executed
agreement, the Companys chief executive 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. Immediately
following the completion of the offering, there were
86,141,291 shares of common stock outstanding, excluding
restricted shares issued.
On October 24, 2007, 17,500 shares of restricted stock
having a value of $365,400 at the date of grant were issued to
outside directors. Although ownership of the shares does not
transfer to the recipients until the shares have vested,
recipients have dividend and voting rights on these shares from
the date of grant. The fair value of each share of restricted
stock was measured based on the market price of the common stock
as of the date of grant and will be amortized over the
respective vesting periods. One-third of the restricted stock
will vest on October 24, 2008, one-third will vest on
October 24, 2009, and the final one-third will vest on
October 24, 2010. Options to purchase 10,300 common shares
at an exercise price of $19.00 per share were granted to outside
directors on October 22, 2007. These awards will vest over
a three year service period and fair value will be measured
using an option-pricing model at the date of grant. The Company
also issued 27,100 shares of common stock to its employees
on October 24, 2007 in connection with the initial public
offering. The compensation expense recorded in the fourth
quarter of 2007 will be $565,848 related to the shares issued.
Nitrogen
Fertilizer Limited Partnership
In conjunction with the consummation of the initial public
offering, CVR transferred CRNF, its nitrogen fertilizer
business, to a newly created limited partnership (Partnership)
in exchange for a managing general partner interest (managing GP
interest), a special general partner interest (special GP
interest, represented by special GP units) and a de minimis
limited partner interest (LP interest, represented by special LP
units). CVR concurrently sold the managing GP interest to an
entity owned by its controlling stockholders and senior
management at fair market value. The board of directors of CVR
determined, after consultation with management, that the fair
market value of the managing general partner interest was
$10.6 million.
The valuation of the managing general partner interest was based
on a discounted cash flow analysis, using a discount rate
commensurate with the risk profile of the managing general
partner interest. The key assumptions underlying the analysis
were commodity price projections, which were used to determine
the Partnerships raw material costs and output revenues.
Other business expenses of the Partnership were based on
managements projections. The Partnerships cash
distributions were assumed to be flat at expected forward
fertilizer prices, with cash reserves developed in periods of
high prices and cash reserves reduced in periods of lower
prices. The Partnerships projected cash flows due to the
managing general partner under the terms of the
Partnerships partnership agreement used for the valuation
were modeled based on the structure of expectations of the
Partnerships operations, including production volumes and
operating costs, which were developed by management based on
historical operations and experience. Price projections were
based on information received from Blue, Johnson &
Associates, a leading fertilizer industry consultant in the
United States which CVR routinely uses for fertilizer market
analysis.
In conjunction with CVRs ownership of the special GP
interest, it will initially own all of the interests in the
Partnership (other than the managing general partner interest
and associated IDRs described below) and will initially be
entitled to all cash that is distributed by the Partnership. The
managing general partner will not be entitled to participate in
Partnership distributions except in respect of associated
incentive distribution rights, or IDRs, which entitle the
managing general partner to receive increasing percentages of
the Partnerships quarterly distributions if the
Partnership increases its distributions above an amount
specified in the partnership agreement. 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 partnership agreement, generated by the Partnership
during the period from its formation through December 31,
2009 has been distributed in respect of the special GP
interests, which CVR will hold,
and/or the
Partnerships common and subordinated interests (none of
which are yet outstanding, but
6
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
which would be issued if the Partnership issues equity in the
future). In addition, there will be no distributions paid on the
managing general partners IDRs for so long as the
Partnership or its subsidiaries are guarantors under
CRLLCs credit facility. The Partnership and its
subsidiaries are currently guarantors under CRLLCs credit
facility.
The Partnership is operated by CVRs senior management
pursuant to a services agreement among CVR, the managing general
partner, and the Partnership. The Partnership is managed by the
managing general partner and, to the extent described below,
CVR, as special general partner. As special general partner of
the Partnership, CVR has joint management rights regarding the
appointment, termination, and compensation of the chief
executive officer and chief financial officer of the managing
general partner, has the right to designate two members of the
board of directors of the managing general partner, and has
joint management rights regarding specified major business
decisions relating to the Partnership.
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 Securities and Exchange Commission.
The consolidated financial statements include the accounts of
CVR Energy, Inc. and its wholly-owned subsidiaries. All
significant intercompany accounts and transactions have been
eliminated in consolidation. Certain information and footnotes
required for the complete financial statements under GAAP have
not been included pursuant to such rules and regulations. These
unaudited condensed consolidated financial statements should be
read in conjunction with the December 31, 2006 audited
financial statements and notes thereto of CVR.
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 December 31, 2006
and September 30, 2007, the results of operations for the
three and nine months ended September 30, 2006 and 2007,
and the cash flows for the nine months ended September 30,
2006 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, 2007 or
any other interim period. The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States 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.
|
|
(2)
|
Pro
Forma Information
|
Earnings per share are calculated on a pro forma basis, based
upon the actual number of shares outstanding at the time of the
initial public offering in October 2007. Pro forma earnings per
share have been based upon the transactions that occurred to
effect the initial public offering, including the merger of
Refining Holdco and CNF with two of CVRs direct wholly
owned subsidiaries; the effect of the 628,667.20 for 1 stock
split of CVRs common stock; the issuance of
247,471 shares of common stock to CVRs chief
executive officer in exchange for his shares in two of
CVRs subsidiaries; the issuance of 27,100 shares of
common stock to CVRs employees; and CVRs issuance of
23,000,000 shares of common stock in the offering. For the
nine month period ended September 30, 2007, the 17,500
nonvested restricted shares of CVR common stock to be issued to
two directors have been excluded from the calculation of pro
forma diluted earnings per share because the inclusion of such
shares in the number of weighted average shares outstanding
would be antidilutive.
7
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pro forma earnings (loss) per share for the three and nine month
periods ended September 30, 2006 and 2007 is calculated as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
Net income (loss)
|
|
$
|
129,038,813
|
|
|
$
|
13,399,189
|
|
|
$
|
170,796,022
|
|
|
$
|
(40,908,276
|
)
|
Pro forma weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Existing CVR common shares
|
|
|
100
|
|
|
|
100
|
|
|
|
100
|
|
|
|
100
|
|
Effect of 628,667.20 to 1 stock split
|
|
|
62,866,620
|
|
|
|
62,866,620
|
|
|
|
62,866,620
|
|
|
|
62,866,620
|
|
Issuance of common shares to management in exchange for
subsidiary shares
|
|
|
247,471
|
|
|
|
247,471
|
|
|
|
247,471
|
|
|
|
247,471
|
|
Issuance of common shares to employees
|
|
|
27,100
|
|
|
|
27,100
|
|
|
|
27,100
|
|
|
|
27,100
|
|
Issuance of common shares in the initial public offering
|
|
|
23,000,000
|
|
|
|
23,000,000
|
|
|
|
23,000,000
|
|
|
|
23,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Dilutive securities issuance of nonvested common
shares to board of directors
|
|
|
17,500
|
|
|
|
17,500
|
|
|
|
17,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma basic earnings (loss) per share
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
Pro forma dilutive earnings (loss) per share
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
The pro forma balance sheet assumes the following transactions
occurred on September 30, 2007:
|
|
|
|
|
The payment of a $10.6 million dividend to the
Companys shareholders of record on October 16, 2007;
|
|
|
|
The receipt of gross proceeds of $10.6 million from the
sale of the managing general partner interest in the Partnership
to Coffeyville Acquisition III LLC, an entity owned by
related parties and management, at estimated fair market value,
as determined by the board of directors after consultation with
management;
|
|
|
|
The exchange of the Companys chief executive
officers shares in two of CVRs subsidiaries
(Refining Holdco and CNF) for shares of CVR common stock at fair
market value, resulting in an estimated
step-up in
basis in the Companys property, plant, and equipment of
approximately $0.6 million;
|
|
|
|
The issuance of 23,000,000 shares of CVR common stock in
connection with the initial public offering at an initial public
offering price of $19.00 per share, resulting in aggregate gross
proceeds of $437.0 million;
|
|
|
|
The payments of underwriters discounts and commissions and
estimated offering expenses totaling approximately
$39.9 million of which $6.6 million had been prepaid
as of September 30, 2007 and $2.6 million had been
accrued as of September 30, 2007;
|
|
|
|
The conversion from a partnership structure to a corporate
structure;
|
8
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
The repayment of term debt of $280.0 million and related
interest of $5.7 million with the net proceeds of the
offering;
|
|
|
|
The repayment of revolver borrowings of $20.0 million,
repayment of borrowings of $25 million under the unsecured
facility, and repayment of borrowings of $25.0 million
under the secured facility, including the related write-off of
approximately $1.3 million of unamortized deferred
financing fees, and the payment of related interest of
$0.2 million; and
|
|
|
|
The payment of a $5.0 million termination fee to each of
Goldman, Sachs & Co. and Kelso & Company,
L.P. in connection with the termination of the management
agreements in conjunction with the initial public offering.
|
|
|
(3)
|
New
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 statement is effective for financial
statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal
years. The Company is currently evaluating the effect that this
statement will have on its financial statements.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities
(SFAS 159). Under this standard, an entity is required
to provide additional information that will assist investors and
other users of financial information to more easily understand
the effect of the companys choice to use fair value on its
earnings. Further, the entity is required to display the fair
value of those assets and liabilities for which the company has
chosen to use fair value on the face of the balance sheet. This
standard does not eliminate the disclosure requirements about
fair value measurements included SFAS No. 107,
Disclosures about Fair Value of Financial Instruments.
SFAS 159 is effective for fiscal years beginning after
November 15, 2007. The Company is currently evaluating the
potential adoption impact that SFAS 159 will have on its
financial statements.
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 as described below. Subsequent to September 30, 2007
and in connection with the split of CALLC into two entities,
managements equity interest in CALLC 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. As of September 30,
2007, common units held by management contained put rights held
by management and call rights held by CALLC exercisable at fair
value in the event the management member became inactive.
Accordingly, in accordance with Emerging Issues Task Force
(EITF) Topic
No. D-98,
Classification and Measurement of Redeemable Securities,
common units held by management were initially recorded at fair
value at the date of issuance and have been classified in
temporary equity as Management Voting Common Units Subject to
Redemption (capital subject to redemption) in the accompanying
condensed consolidated balance sheets. The put rights and call
rights were eliminated in October 2007.
CVR accounted for changes in redemption value of management
common units in the period the changes occurred and adjusted the
carrying value of the capital subject to redemption to equal the
redemption value at the end of each reporting period with an
equal and offsetting adjustment to Members Equity. None of
the capital subject to redemption was redeemable at
December 31, 2006 or September 30, 2007.
At September 30, 2007, the capital subject to redemption
was revalued through an independent appraisal process, and the
value was determined to be $43.05 per unit. The valuation was
based upon a calculation utilizing
9
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the initial public offering share price. This methodology
provided the best estimate of the value as it was based upon
actual information supporting the value. The recognition of the
value of $43.05 per unit increased the carrying value of the
capital subject to redemption by $2,035,354 for the nine months
ended September 30, 2007 with an equal and offsetting
decrease to Members Equity. The increase was primarily
attributable to favorable market conditions in the fertilizer
sector.
919,630
override operating units at an adjusted benchmark value of
$11.31 per unit
In June 2005, CALLC issued nonvoting override operating units to
certain management members holding common units. There were no
required capital contributions for the override operating units.
In accordance with SFAS 123(R), Share Based
Compensation, using the Monte Carlo method of valuation, the
estimated fair value of the override operating units on
June 24, 2005 was $3,604,950. Pursuant to the forfeiture
schedule described below, the Company is recognizing
compensation expense over the service period for each separate
portion of the award for which the forfeiture restriction lapsed
as if the award was, in-substance, multiple awards. Compensation
expense of $177,943 and $743,137 were recognized for the three
and nine month periods ending September 30, 2007,
respectively. Compensation expenses of $291,679 and $865,527
were recognized for the three and nine month periods ending
September 30, 2006, respectively. Significant assumptions
used in the valuation were as follows:
|
|
|
|
|
|
|
Estimated forfeiture rate
|
|
None
|
|
|
Explicit service period
|
|
Based on forfeiture schedule below
|
|
|
Grant-date fair value controlling basis
|
|
$5.16 per share
|
|
|
Marketability and minority interest discounts
|
|
$1.24 per share (24% discount)
|
|
|
Volatility
|
|
37%
|
72,492
override operating units at a benchmark value of $34.72 per
unit
On December 28, 2006, CALLC issued additional nonvoting
override operating units to a certain management member who
holds common units. There were no required capital contributions
for the override operating units.
In accordance with SFAS 123(R), a combination of a binomial
model and a probability-weighted expected return method which
utilized the companys cash flow projections resulted in an
estimated fair value of the override operating units on
December 28, 2006 was $472,648. Management believed that
this method was preferable for the valuation of the override
units as it allowed a better integration of the cash flows with
other inputs, including the timing of potential exit events that
impact the estimated fair value of the override units. Pursuant
to the forfeiture schedule described below, the Company is
recognizing compensation expense over the service period for
each separate portion of the award for which the forfeiture
restriction lapsed as if the award was, in-substance, multiple
awards. Compensation expense for the three and nine month
periods ended September 30, 2007 was $40,532 and $236,433,
respectively. Significant assumptions used in the valuation were
as follows:
|
|
|
|
|
|
|
Estimated forfeiture rate
|
|
None
|
|
|
Explicit service period
|
|
Based on forfeiture schedule below
|
|
|
Grant-date fair value controlling basis
|
|
$8.15 per share
|
|
|
Marketability and minority interest discounts
|
|
$1.63 per share (20% discount)
|
|
|
Volatility
|
|
41%
|
Override operating units participate in distributions from CALLC
(and, following the split of CALLC into two entities, CALLC
II) in proportion to the number of total common,
non-forfeited override operating and participating override
value units issued. Distributions to override operating units
will be reduced until the total cumulative reductions are equal
to the benchmark value. Override operating units are forfeited
upon termination of
10
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
employment for cause. In the event of all other terminations of
employment, the override operating units are initially subject
to forfeiture with the number of units subject to forfeiture
reducing as follows:
|
|
|
|
|
|
|
Forfeiture
|
|
Minimum Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
On the tenth anniversary of the issuance of override operating
units, such units shall convert into an equivalent number of
override value units.
1,839,265
override value units at an adjusted benchmark value of $11.31
per unit
In June 2005, CALLC issued nonvoting override value units to
certain management members holding common units. There were no
required capital contributions for the override value units.
In accordance with SFAS 123(R), using the Monte Carlo
method of valuation, the estimated fair value of the override
value units on June 24, 2005 was $4,064,776. For the
override value units, CVR is recognizing compensation expense
ratably over the implied service period of 6 years.
Compensation expense of $508,097 was recognized for both the
nine months ending September 30, 2006 and 2007.
Compensation expense of $169,366 was recognized for both the
three months ending September, 30, 2006 and 2007. Significant
assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Estimated forfeiture rate
|
|
None
|
|
|
Derived service period
|
|
6 years
|
|
|
Grant-date fair value controlling basis
|
|
$2.91 per share
|
|
|
Marketability and minority interest discounts
|
|
$0.70 per share (24% discount)
|
|
|
Volatility
|
|
37%
|
144,966
override value units at a benchmark value of $34.72 per
unit
On December 28, 2006, CALLC issued additional nonvoting
override value units to a certain management member who holds
common units. There were no required capital contributions for
the override value units.
In accordance with SFAS 123(R), a combination of a binomial
model and a probability-weighted expected return method which
utilized the Companys cash flow projections resulted in an
estimated fair value of the override value units on
December 28, 2006 of $945,178. Management believed that
this method was preferable for the valuation of the override
units as it allowed a better integration of the cash flows with
other inputs, including the timing of potential exit events that
impact the estimated fair value of the override units. For the
override value units, CVR is recognizing compensation expense
ratably over the implied service period of 6 years.
Compensation expense for the three and nine month periods ended
September 30, 2007 was $51,555 and $154,666. Significant
assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Estimated forfeiture rate
|
|
None
|
|
|
Derived service period
|
|
6 years
|
|
|
Grant-date fair value controlling basis
|
|
$8.15 per share
|
|
|
Marketability and minority interest discounts
|
|
$1.63 per share (20% discount)
|
|
|
Volatility
|
|
41%
|
11
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Value units fully participate in cash distributions by CALLC
(and, following the split of CALLC into two entities, CALLC
II) when the amount of such cash distributions to certain
investors (Current Common Value) is equal to four times the
original contributed capital of such investors (including the
Delayed Draw Capital required to be contributed pursuant to the
long term credit agreements). If the Current Common Value is
less than two times the original contributed capital of such
investors at the time of a distribution, none of the override
value units participate. In the event the Current Common Value
is greater than two times the original contributed capital of
such investors but less than four times, the number of
participating override value units is the product of 1) the
number of issued override value units and 2) a fraction,
the numerator of which is the Current Common Value minus two
times original contributed capital, and the denominator of which
is two times the original contributed capital. Distributions to
participating override value units will be reduced until the
total cumulative reductions are equal to the benchmark value. On
the tenth anniversary of any override value unit (including any
override value unit issued on the conversion of an override
operating unit) the two times threshold referenced
above will become 10 times and the four
times threshold referenced above will become 12
times. Unless the compensation committee of the board of
directors of CALLC (and, following the split of CALLC into two
entities, CALLC II) takes an action to prevent forfeiture,
override value units are forfeited upon termination of
employment for any reason except that in the event of
termination of employment by reason of death or disability, all
override value units are initially subject to forfeiture with
the number of units subject to forfeiture reducing as follows:
|
|
|
|
|
|
|
Subject to
|
|
|
|
Forfeiture
|
|
Minimum Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
At September 30, 2007, there was approximately
$4.6 million of unrecognized compensation expense related
to nonvoting override units. This is expected to be recognized
over a period of five years as follows:
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
|
|
Operating Units
|
|
|
Value Units
|
|
|
Three months ending December 31, 2007
|
|
$
|
218,476
|
|
|
$
|
220,921
|
|
Year ending December 31, 2008
|
|
|
670,385
|
|
|
|
883,684
|
|
Year ending December 31, 2009
|
|
|
344,178
|
|
|
|
883,684
|
|
Year ending December 31, 2010
|
|
|
102,079
|
|
|
|
883,684
|
|
Year ending December 31, 2011
|
|
|
|
|
|
|
385,383
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,335,118
|
|
|
$
|
3,257,356
|
|
|
|
|
|
|
|
|
|
|
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, 2007, the issued Profits Interest (combined
phantom plan and override units) represented 15% of combined
common unit interest and Profits Interest of CALLC. 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 proposed initial public offering
price to determine the Companys equity value, through an
independent valuation process, the
12
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
service phantom interest was valued at $39.61 per point and the
performance phantom interest was valued at $39.61 per point. CVR
has recorded $10,817,390 and $20,458,877 in personnel accruals
as of December 31, 2006 and September 30, 2007,
respectively. Compensation expense for the three and nine month
periods ended September 30, 2007 related to the Phantom
Unit Plan was $4,061,877 and $9,641,487, respectively.
Compensation expense for the three and nine months ended
September 30, 2006 related to the Phantom Unit Plan was
($475,754) and $900,496, respectively.
At September 30, 2007 there was approximately
$21.1 million of unrecognized compensation expense related
to the Phantom Unit Plan. This is expected to be recognized over
a period of five years.
Subsequent to September 30, 2007, in connection with the
Companys initial public offering, the Company has created
a second phantom unit appreciation plan with respect to CALLC II
which mirrors in all respects the Phantom Unit Appreciation Plan
as it relates to CALLC.
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
moving-average cost, which approximates the
first-in,
first-out (FIFO) method, or market for fertilizer products and
at the lower of FIFO cost or market for 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 average cost, which
approximates FIFO, or market. The cost of inventories includes
inbound freight costs.
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
Finished goods
|
|
$
|
59,722
|
|
|
$
|
94,069
|
|
Raw materials and catalysts
|
|
|
60,810
|
|
|
|
79,507
|
|
In-process inventories
|
|
|
18,441
|
|
|
|
15,901
|
|
Parts and supplies
|
|
|
22,460
|
|
|
|
20,376
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
161,433
|
|
|
$
|
209,853
|
|
|
|
|
|
|
|
|
|
|
|
|
(6)
|
Planned
Major Maintenance Costs
|
The direct-expense method of accounting is used for planned
major maintenance activities. Maintenance costs are recognized
as expense when maintenance services are performed. The
Coffeyville nitrogen plant last completed a major scheduled
turnaround in the third quarter of 2006. The Coffeyville
refinery started a major scheduled turnaround in February 2007
with completion in April 2007. Costs of $76,754,014 associated
with the 2007 turnaround were included in direct operating
expenses (exclusive of depreciation and amortization) for the
nine months ended September 30, 2007. No costs were
incurred for the three months ended September 30, 2007.
Costs of $4,069,189 and $4,407,137 associated primarily with the
2006 turnaround for the nitrogen plant were included in direct
operating expenses (exclusive of depreciation and amortization)
for the three and nine months ended September 30, 2006,
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 $595,046 and $1,791,563 for the three and nine
months ended September 30, 2007, respectively.
13
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cost of product sold excludes depreciation and amortization of
$529,738 and $1,553,030 for the three and nine months ended
September 30, 2006, respectively.
Direct operating expenses (exclusive of depreciation and
amortization) includes direct costs of labor, maintenance and
services, energy and utility costs, environmental compliance
costs as well as chemicals and catalysts and other direct
operating expenses. Direct operating expenses exclude
depreciation and amortization of $9,582,478 and $40,201,920 for
the three and nine months ended September 30, 2007,
respectively. Direct operating expenses exclude depreciation and
amortization of $11,682,825 and $34,528,780 for the three and
nine months ended September 30, 2006, respectively. Direct
operating expenses also exclude depreciation of $7,627,072 for
both the three and nine months ended September 30, 2007
that is included in Net costs associated with flood
on the consolidated statement of operations as a result of the
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 $303,541 and $680,040 for the three and nine
months ended September 30, 2007, respectively. Selling,
general and administrative expense excludes depreciation and
amortization of $574,973 and $727,834 for the three and nine
months ended September 30, 2006, respectively.
As a result of the flood and crude oil discharge, see
Note 10, Flood, and Note 12,
Commitments and Contingent Liabilities, the
Companys subsidiaries entered into three new credit
facilities in August 2007. Two of these facilities were
subsequently repaid in full with proceeds from the initial
public offering and the third facility terminated in connection
with the initial public offering. CRLLC entered into a new
$25 million senior secured term loan (the $25 million
secured facility). The facility was secured by the same
collateral that secured the Companys existing Credit
Facility. Interest was payable in cash, at the Companys
option, at the base rate plus 1.0% or the reserve adjusted
Eurodollar rate plus 2.00%. CRLLC also entered into a new
$25 million senior unsecured term loan (the
$25 million unsecured facility). Interest was payable in
cash, at the Companys option, at the base rate plus 1.0%
or the reserve adjusted Eurodollar rate plus 2.00%. A subsidiary
of CALLC, Refining Holdco, entered into a new $75 million
senior unsecured term loan (the $75 million unsecured
facility). Drawings could be made from time to time in amounts
of at least $5 million. Interest accrued, at the
borrowers option, at the base rate plus 1.50% or at the
reserve adjusted Eurodollar rate plus 2.50%. Interest was paid
by adding such interest to the principal amount of loans
outstanding. In addition, a commitment fee equal to 1.00%
accrued and was paid by adding such fees to the principal amount
of loans outstanding. No amount was ever drawn on the
$75 million unsecured facility.
The sole lead arranger and sole bookrunner for each of these
facilities was Goldman Sachs Credit Partners L.P. The
Companys obligations under the $25 million secured
facility and the $25 million unsecured facility were
guaranteed by substantially all of the Companys
subsidiaries. The $75 million unsecured facility was
guaranteed by CALLC. In addition, each of GS Capital
Partners V, L.P. and Kelso Investment Associates VII, L.P.
guaranteed 50% of the aggregate amount of each of the three
facilities. The maturity of each of these three facilities was
January 31, 2008, with an automatic extension to
August 23, 2008 upon completion of an initial public
offering. The secured and unsecured credit facilities were paid
in full on October 26, 2007 with proceeds from CVRs
initial public offering, see Note 1, Organization,
Initial Public Offering, and Basis of Presentation, and
both facilities were terminated. Interest accrued of
approximately $0.2 million through the payment date on
these two facilities was also paid with proceeds from the
initial public offering. Additionally, in connection with the
consummation of the initial public offering, the
$75 million unsecured facility also terminated.
In connection with the repayment of the $25 million secured
facility and the $25 million unsecured facility with the
proceeds of CVRs initial public offering, the Company
expects to write off approximately $1.3 million of deferred
financing fees in the fourth quarter of 2007.
14
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company repaid $280 million of term debt with proceeds
from the initial public offering. Associated accrued interest
was paid of $5.7 million. After the initial public
offering, the Company had approximately $491.1 million of
First Lien Tranche D term loans outstanding and
$7.2 million of outstanding borrowings under its Revolving
Loan Facility.
The Company entered into an insurance premium finance agreement
with Cananwill, Inc. in July 2007 to finance the purchase of its
property, liability, cargo and terrorism policies. The
approximately $5.9 million note will be repaid in nine
equal installments with final payment in April 2008.
On June 30, 2007, torrential rains in southeast Kansas
caused the Verdigris River to overflow its banks and flood the
town of Coffeyville, Kansas. As a result, the Companys
refinery and nitrogen fertilizer plant were severely flooded
resulting in significant damage to the refinery assets. The
nitrogen fertilizer facility also sustained damage, but to a
much lesser degree. The Company maintains property damage
insurance which includes damage caused by a flood of up to
$300 million per occurrence subject to deductibles and
other limitations. The deductible associated with the property
damage is $2.5 million.
Management is working closely with the Companys insurance
carriers and claims adjusters to ascertain the full amount of
insurance proceeds due to the Company as a result of the damages
and losses. The Company has recognized a receivable from
insurance at September 30, 2007 which management believes
is probable of recovery from the insurance carriers. While
management believes that the Companys property insurance
should cover substantially all of the estimated total physical
damage to the property, the Companys insurance carriers
have cited potential coverage limitations and defenses that
might preclude such a result.
The Companys insurance policies also provide coverage for
interruption to the business, including lost profits, and
reimbursement for other expenses and costs the Company has
incurred relating to the damages and losses suffered for
business interruption. This coverage, however, only applies to
losses incurred after a business interruption of 45 days.
Because the fertilizer plant was restored to operation within
this 45-day
period and the refinery restarted its last operating unit in
48 days, a substantial portion of the lost profits incurred
because of the flood cannot be claimed under insurance. The
Company is assessing its policies to determine how much, if any,
of its lost profits after the
45-day
period are recoverable. No amounts for recovery of lost profits
under the Companys business interruption policy have been
recorded in the accompanying consolidated financial statements.
As of September 30, 2007, the Company has recorded pretax
costs of approximately $34.3 million associated with the
flood and related crude oil discharge as discussed in
Note 12, Commitments and Contingent
Liabilities, including $32.2 million in the third
quarter of 2007. These amounts were net of anticipated insurance
recoveries of approximately $96.4 million. The components
of the net costs as of September 30, 2007 include
$3.5 million for uninsured losses within the Companys
insurance deductibles; $7.6 million for depreciation for
the temporarily idled facilities; $5.1 million as a result
of other uninsured expenses incurred which included salaries of
$1.2 million, professional fees of $1.1 million and
other miscellaneous amounts of $2.8 million. The
$34.3 million net costs also included approximately
$18.1 million recorded with respect to the environmental
remediation and property damage as discussed in Note 12,
Commitments and Contingent Liabilities. These costs
are reported in Net costs associated with flood in
the Consolidated Statements of Operations.
Total gross costs recorded due to the flood and related oil
discharge that were included in the statement of operations for
the three and nine months ended September 30, 2007 were
approximately $128.6 million and $130.7 million. Of
these gross costs for the nine month period ended
September 30, 2007, approximately $91.2 million were
associated with repair and other matters as a result of the
flood damage to the Companys facilities. Included in this
cost was $7.6 million of depreciation for temporarily idled
facilities, $5.9 million of
15
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
salaries, $2.9 million of professional fees and
$74.8 million for other repair and related costs. There
were approximately $39.5 million costs recorded for the
nine month period ended September 30, 2007 related to the
third party and property damage remediation as a result of the
crude oil discharge. Total accounts receivable from insurers for
flood related matters approximated $96.4 million at
September 30, 2007, for which we believe collection is
probable, including $21.4 million related to the crude oil
discharge and $75.0 million as a result of the flood damage
to the Companys facilities.
The Company anticipates that approximately $15.5 million in
additional third party costs related to the repair of flood
damaged property will be recorded in future periods. The total
third party cost to repair the refinery is currently estimated
at approximately $86 million, and the total third party
cost to repair the nitrogen fertilizer facility is currently
estimated at approximately $4 million. 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.
As of September 30, 2007, the Company had not received any
insurance proceeds. As of November 30, 2007, the Company
received insurance proceeds of $10 million under its
property insurance policy, and an additional $10 million
under its environmental policies related to recovery of certain
costs associated with the crude oil discharge. See Note 12,
Commitments and Contingent Liabilities for
additional information regarding environmental and other
contingencies relating to the crude oil discharge that occurred
on July 1, 2007.
In June 2006, the FASB issued FASB Interpretation No. (FIN) 48,
Accounting for Uncertain Tax Positions an
interpretation of FASB No. 109. FIN 48 clarifies
the accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with FASB
109, by prescribing a minimum financial statement recognition
threshold and measurement attribute for a tax position taken or
expected to be taken in a tax return. FIN 48 also provides
guidance on derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition.
The Company adopted the provisions of 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, 2007.
Accordingly, the Company did not accrue or recognize any amounts
for interest or penalties in its financial statements for the
three and nine months ended September 30, 2007. The Company
will classify interest to be paid on an underpayment of income
taxes and any related penalties as income tax expense if it is
determined, in a subsequent period, that a tax position is not
more likely than not of being sustained.
CVR Energy and its subsidiaries file U.S. federal and
various state income tax returns. The Company has not been
subject to U.S. federal, state and local income tax
examinations by tax authorities for any tax year. The
U.S. federal and state tax years subject to examination are
2004 to 2006.
The Companys effective tax rate for the three and nine
months ended September 30, 2007 was 78.0% and 69.4%,
respectively, as compared to the federal statutory tax rate of
35%. The effective tax rate is higher primarily due to the
correlation between the amount of credits which are projected to
be generated for the production of ultra low sulfur diesel fuel
in 2007 and the reduced level of projected pre-tax income for
2007.
The Company received credit certification from the Kansas
Department of Commerce under the High Performance Incentive
Program (HPIP) subsequent to September 30, 2007. Under the
HPIP program, the Company anticipates that it will record a
significant state income tax benefit in the fourth quarter of
2007 related to credits
16
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
earned on certain property placed in service for 2007 and 2006.
The recognition of the credit earned will significantly increase
the income tax benefit recorded in the fourth quarter of 2007.
|
|
(12)
|
Commitments
and Contingent Liabilities
|
The minimum required payments for the Companys lease
agreements and unconditional purchase obligations are as follows:
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Unconditional
|
|
|
|
Leases
|
|
|
Purchase Obligations
|
|
|
Three months ending December 31, 2007
|
|
$
|
871,757
|
|
|
$
|
5,191,066
|
|
Year ending December 31, 2008
|
|
|
3,890,431
|
|
|
|
19,696,879
|
|
Year ending December 31, 2009
|
|
|
2,940,476
|
|
|
|
19,662,470
|
|
Year ending December 31, 2010
|
|
|
1,591,818
|
|
|
|
44,745,277
|
|
Year ending December 31, 2011
|
|
|
857,494
|
|
|
|
42,843,860
|
|
Year ending December 31, 2012
|
|
|
106,038
|
|
|
|
40,157,893
|
|
Thereafter
|
|
|
2,025
|
|
|
|
318,035,461
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,260,039
|
|
|
$
|
490,332,906
|
|
|
|
|
|
|
|
|
|
|
The Company leases various equipment and real properties under
long-term operating leases. For the three and nine months ended
September 30, 2007, lease expense totaled $850,354, and
$2,812,202, respectively. For the three and nine months ended
September 30, 2006, lease expense totaled $985,251 and
$2,823,689, 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.
The Company executed a Petroleum Transportation Service
Agreement in June 2007 with TransCanada Keystone Pipeline, LP
(TransCanada). TransCanada is proposing to construct, own and
operate a pipeline system and a related extension and expansion
of the capacity that would terminate near Cushing, Oklahoma.
TransCanada has agreed to transport a contracted volume amount
of at least 25,000 barrels per day with a Cushing Delivery
Point as the contract point of delivery. The contract term is a
10 year period which will commence upon the completion of
the pipeline system. The expected date of commencement is the
fourth quarter of 2010 with termination of the transportation
agreement estimated to be February 2020. The Company will pay a
fixed and variable toll rate beginning during the month of
commencement.
From time to time, the Company is involved in various lawsuits
arising in the normal course of business, including matters such
as those described below under, Environmental, Health, and
Safety Matters. Liabilities related to such lawsuits are
recognized when the related costs are probable and can be
reasonably estimated. Management believes the Company has
accrued for losses for which it may ultimately be responsible.
It is possible managements estimates of the outcomes will
change within the next year due to uncertainties inherent in
litigation and settlement negotiations. In the opinion of
management, the ultimate resolution of any other litigation
matters is not expected to have a material adverse effect on the
accompanying consolidated financial statements. There can be no
assurance that managements beliefs or opinions with
respect to liability for potential litigation matters are
accurate.
Crude oil was discharged from the Companys refinery on
July 1, 2007 due to the short amount of time available to
shut down and secure the refinery in preparation for the flood
that occurred on June 30, 2007. As a result of the crude
oil discharge, two putative class action lawsuits (one federal
and one state) were filed seeking unspecified damages with class
certification under applicable law for all residents,
domiciliaries and property owners of Coffeyville, Kansas who
were impacted by the oil release.
17
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company filed a motion to dismiss the federal suit for lack
of subject matter jurisdiction. On November 6, 2007, the
judge in the federal class action lawsuit granted the
Companys motion to dismiss. Due to the uncertainty of the
state suit, the Company is unable to estimate a range of
possible loss at this time for this exposure in excess of the
amount accrued for the proposed purchase of homes and commercial
property noted below. The Company intends to defend the state
suit vigorously. Presently, the Company does not expect that the
resolution of the suit will have a significant adverse effect on
its business and results of operations.
As a result of the crude oil discharge that occurred on
July 1, 2007, the Company entered into an administrative
order on consent (the Consent Order) with the EPA on
July 10, 2007. As set forth in the Consent Order, the EPA
concluded that the discharge of oil from the Companys
refinery caused and may continue to cause an imminent and
substantial threat to the public health and welfare. Pursuant to
the Consent Order, the Company agreed to perform specified
remedial actions to respond to the discharge of crude oil from
the Companys refinery. The Company is currently
remediating the crude oil discharge and expects its remedial
actions to continue until December 2007.
The Company engaged experts to assess and test the areas
affected by the crude oil spill. The Company commenced a program
on July 19, 2007 to purchase approximately 320 homes and
other commercial properties in connection with the flood and the
crude oil release. The costs recorded as of September 30,
2007 related to the obligation of the homes being purchased,
were approximately $11.5 million, and are included in
Net Costs Associated With Flood in the accompanying
consolidated statement of operations. Costs recorded related to
personal property claims were approximately $1.7 million as
of September 30, 2007. The costs recorded related to
estimated commercial property to be purchased and associated
claims were approximately $3.6 million as of
September 30, 2007. The total amount of gross costs
recorded for the three and nine months ended September 30,
2007 related to the residential and commercial purchase and
property claims program were approximately $16.8 million.
As of September 30, 2007, the total costs recorded for
obligations other than the purchase of homes, commercial
properties, and related personal property claims, approximated
$22.7 million. The Company has recorded as of
September 30, 2007, total costs (net of anticipated
insurance recoveries recorded of $21.4 million) associated
with remediation and third party property damage claims
resolution of approximately $18.1 million. The Company has
not estimated or accrued for, because management does not
believe it is probable that there will be any potential fines,
penalties or claims that may be imposed or brought by regulatory
authorities or possible additional damages arising from class
action lawsuits related to the flood.
It is difficult to estimate the ultimate cost of environmental
remediation resulting from the crude oil discharge or the cost
of third party property damage that the Company will ultimately
be required to pay. The costs and damages that the Company will
ultimately pay may be greater than the amounts described and
projected above. Such excess costs and damages could be material
to the consolidated financial statements.
The Company is seeking insurance coverage for this release and
for the ultimate costs for remediation, property damage claims,
cleanup, resolution of class action lawsuits, and other claims
brought by regulatory authorities. Although the Company believes
that it will recover substantial sums under its environmental
and liability insurance policies, the Company is not sure of the
ultimate amount or timing of such recovery because of the
difficulty inherent in projecting the ultimate resolution of the
Companys claims. The difference between what the Company
receives under its insurance policies compared to what has been
recorded and described above could be material to the
consolidated financial statements. The Company has received
$10 million of insurance proceeds under its environmental
insurance policy as of November 30, 2007.
Environmental,
Health, and Safety (EHS) Matters
CVR is subject to various stringent federal, state, and local
EHS rules and regulations. Liabilities related to EHS matters
are recognized when the related costs are probable and can be
reasonably estimated. Estimates of these costs are based upon
currently available facts, existing technology, site-specific
costs, and currently enacted laws
18
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
The Company agreed to perform corrective action pursuant to two
Administrative Orders on Consent issued to Farmland Industries,
Inc. (predecessor entity to the Company) under the Resource
Conservation and Recovery Act, as amended (RCRA), for the
Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal.
In 2005, Coffeyville Resources Nitrogen Fertilizers, LLC agreed
to participate in the State of Kansas Voluntary Cleanup and
Property Redevelopment Program (VCPRP) to address a reported
release of urea ammonium nitrate (UAN) at the Coffeyville UAN
loading rack. As of December 31, 2006 and
September 30, 2007, environmental accruals of $7,222,754
and $7,177,347, respectively, were reflected in the consolidated
balance sheets for probable and estimated costs for remediation
of environmental contamination under the RCRA Administrative
Orders and the VCPRP, including amounts totaling $1,827,649 and
$1,573,463, respectively, included in other current liabilities.
The accruals were determined based on an estimate of payment
costs through 2033, which scope of remediation was arranged with
the Environmental Protection Agency (the EPA) and are discounted
at the appropriate risk free rates at December 31, 2006 and
September 30, 2007, respectively. The accruals include
estimated closure and post-closure costs of $1,857,000 and
$1,809,000 for two landfills at December 31, 2006 and
September 30, 2007, respectively. The estimated future
payments for these required obligations are as follows (in
thousands):
|
|
|
|
|
|
|
Amount
|
|
|
Three months ending December 31, 2007
|
|
$
|
518
|
|
Year ending December 31, 2008
|
|
|
1,302
|
|
Year ending December 31, 2009
|
|
|
919
|
|
Year ending December 31, 2010
|
|
|
587
|
|
Year ending December 31, 2011
|
|
|
354
|
|
Year ending December 31, 2012
|
|
|
760
|
|
Thereafter
|
|
|
5,184
|
|
|
|
|
|
|
Undiscounted total
|
|
|
9,624
|
|
Less amounts representing interest at 4.67%
|
|
|
2,447
|
|
|
|
|
|
|
Accrued environmental liabilities at September 30, 2007
|
|
$
|
7,177
|
|
|
|
|
|
|
In March 2004, a predecessor entity to CVR entered into a
Consent Decree with the EPA and the Kansas Department of Health
and Environment (KDHE) related to Farmland Industries,
Inc.s prior operation of the Companys oil refinery.
Under the Consent Decree, the Company agreed to install controls
on certain process equipment and make certain operational
changes at the refinery. As a result of this agreement to
install certain controls and implement certain operational
changes, the EPA and KDHE agreed not to impose civil penalties,
and provided a release from liability for Farmlands
alleged noncompliance with the issues addressed by the Consent
Decree. Pursuant to the Consent Decree, in the short term, the
Company has increased the use of catalyst additives to the fluid
catalytic cracking unit at the facility to reduce emissions of
SO2.
The Company will begin adding catalyst to reduce oxides of
nitrogen, or NOx, in 2008. In the longer term, the Company will
install controls to minimize
SO2
emissions and will install controls or otherwise reduce NOx
emissions by January 1, 2011. There are other permitting,
monitoring, record-keeping and reporting requirements associated
with the Consent Decree. The overall cost of complying with the
Consent Decree is expected to be approximately $41 million,
of which approximately $35 million is expected to be
capital expenditures. The estimated costs do not include the
cleanup obligations that
19
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Company assumed pursuant to the Consent Decree under the
Administrative Orders on Consent previously described.
The EPA is continuing with its Petroleum Refining Initiative
alleging industry-wide noncompliance with four
marquee issues: New Source Review, flaring, leak
detection and repair, and Benzene Waste Operations NESHAP. The
Petroleum Refining Initiative has resulted in many refiners
entering into consent decrees imposing civil penalties and
requiring substantial expenditures for additional or enhanced
pollution control. At this time, management does not know how,
if at all, the Petroleum Refining Initiative will affect the
Company as the current Consent Decree covers some, but not all,
of the marquee issues.
On November 15, 2007, the Governor of Kansas, Kathleen
Sebelius, signed the Midwestern Greenhouse Gas Accord, whereby
six states and the Canadian Province of Manitoba agreed to
endeavor to establish greenhouse gas reduction targets and
develop a market-based and multi-sector
cap-and-trade
mechanism to achieve these reduction targets. At the time,
management does not know to what extent the Midwestern
Greenhouse Gas Accord will affect the Company, and its
facilities that emit greenhouse gases, could be regulated.
Periodically, the Company receives communications from various
federal, state and local governmental authorities asserting
violation(s) of environmental laws
and/or
regulations. These governmental entities may also propose or
assess fines or require corrective action for these asserted
violations. The Company intends to respond in a timely manner to
all such communications and to take appropriate corrective
action. The Company does not anticipate that any such matters
currently asserted will have a material adverse impact on the
financial condition, results of operations or cash flows.
Management periodically reviews and, as appropriate, revises its
environmental accruals. Based on current information and
regulatory requirements, management believes that the accruals
established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of
sulfur in diesel and gasoline. The EPA has granted the Company a
petition for a technical hardship waiver with respect to the
date for compliance in meeting the sulfur-lowering standards.
CVR has spent approximately $2 million in 2004,
$27 million in 2005, $79 million in 2006,
$17 million in the first nine months of 2007 and, based on
information currently available, anticipates spending
approximately $0 million in the last three months of 2007,
$5 million in 2008, $18 million in 2009, and
$22 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 nine month period ended September 30, 2006 and
2007, capital expenditures were $172,950,392 and $102,775,474,
respectively, and were incurred to improve the environmental
compliance and efficiency of the operations.
CVR believes it is in substantial compliance with existing EHS
rules and regulations. There can be no assurance that the EHS
matters described above or other EHS matters which may develop
in the future will not have a material adverse effect on the
business, financial condition, or results of operations.
20
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(13)
|
Derivative
Financial Instruments
|
Loss on derivatives consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Realized loss on swap agreements
|
|
$
|
(12,735,079
|
)
|
|
$
|
(45,351,557
|
)
|
|
$
|
(46,147,786
|
)
|
|
$
|
(142,566,824
|
)
|
Unrealized gain (loss) on swap agreements
|
|
|
178,545,946
|
|
|
|
90,196,226
|
|
|
|
80,322,487
|
|
|
|
(98,294,206
|
)
|
Realized gain (loss) on other agreements
|
|
|
8,809,112
|
|
|
|
(1,246,747
|
)
|
|
|
6,146,779
|
|
|
|
(8,833,758
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
1,127,332
|
|
|
|
726,178
|
|
|
|
1,530,184
|
|
|
|
(837,339
|
)
|
Realized gain on interest rate swap agreements
|
|
|
1,398,512
|
|
|
|
964,675
|
|
|
|
3,139,935
|
|
|
|
3,282,117
|
|
Unrealized loss on interest rate swap agreements
|
|
|
(5,936,928
|
)
|
|
|
(4,756,280
|
)
|
|
|
(244,746
|
)
|
|
|
(4,661,929
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives
|
|
$
|
171,208,895
|
|
|
$
|
40,532,495
|
|
|
$
|
44,746,853
|
|
|
$
|
(251,911,939
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CVR is subject to price fluctuations caused by supply
conditions, weather, economic conditions, and other factors and
to interest rate fluctuations. To manage price risk on crude oil
and other inventories and to fix margins on certain future
production, CVR may enter into various derivative transactions.
In addition, CALLC, as further described below, entered into
certain commodity derivate contracts and an interest rate swap
as required by the long-term debt agreements.
CVR has adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities,
(SFAS 133). 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.
At September 30, 2007, CVRs Petroleum Segment held
commodity derivative contracts (swap agreements) for the period
from July 1, 2005 to June 30, 2010 with a related
party (see Note 14, Related Party
Transactions). The swap agreements were originally
executed by CALLC on June 16, 2005 and were required under
the terms of the Companys long-term debt agreements. The
notional quantities on the date of execution were
100,911,000 barrels of crude oil; 1,889,459,250 gallons of
heating oil and 2,348,802,750 gallons of unleaded gasoline. The
swap agreements were executed at the prevailing market rate at
the time of execution and management believes the swap
agreements provide an economic hedge on future transactions. At
September 30, 2007 the notional open amounts under the swap
agreements were 48,496,750 barrels of crude oil,
1,018,431,750 gallons of heating oil and 1,018,431,750 gallons
of unleaded gasoline. These positions resulted in unrealized
gains (losses) for the three and nine month periods ended
September 30, 2007 of $90,196,226 and $(98,294,206),
respectively, using a valuation method that utilizes quoted
market prices and assumptions for the estimated forward yield
curves of the related commodities in periods when quoted market
prices are unavailable. Unrealized gains were recorded for the
three and nine month periods ended September 30, 2006 of
$178,545,946 and $80,322,487. The Petroleum Segment recorded
$(45,351,557) and $(142,566,824) in realized gains (losses) on
these swap agreements for the three and nine month periods ended
September 30, 2007, respectively. Realized gains (losses)
for the three and nine months ended September 30, 2006 were
recorded of $(12,735,079) and $(46,147,786), respectively.
The Petroleum Segment also recorded mark-to-market net gains
(losses), exclusive of the swap agreements described above and
the interest rate swaps described in the following paragraph, in
gain (loss) on derivatives of $(520,569), and $(9,671,097), for
the three and nine month periods ended September 30, 2007,
respectively and $9,936,444 and $7,676,963 for the three and
nine month periods ended September 30, 2006, respectively.
All of the activity related to the commodity derivative
contracts is reported in the Petroleum Segment.
21
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At September 30, 2007, CRLLC held derivative contracts
known as interest rate swap agreements that converted
CRLLCs floating-rate bank debt into 4.195% fixed-rate debt
on a notional amount of $325,000,000. Half of the agreements are
held with a related party (as described in Note 14,
Related Party Transactions), and the other half are
held with a financial institution that is a lender under
CRLLCs long-term debt agreements. The swap agreements
carry the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Fixed
|
|
Period Covered
|
|
Amount
|
|
|
Interest Rate
|
|
|
June 29, 2007 to March 30, 2008
|
|
|
325 million
|
|
|
|
4.195
|
%
|
March 31, 2008 to March 30, 2009
|
|
|
250 million
|
|
|
|
4.195
|
%
|
March 31, 2009 to March 30, 2010
|
|
|
180 million
|
|
|
|
4.195
|
%
|
March 31, 2010 to June 29, 2010
|
|
|
110 million
|
|
|
|
4.195
|
%
|
CVR pays the fixed rates listed above and receives a floating
rate based on three-month LIBOR rates, with payments calculated
on the notional amounts listed above. The notional amounts do
not represent actual amounts exchanged by the parties but
instead represent the amounts on which the contracts are based.
The swap is settled quarterly and marked to market at each
reporting date, and all unrealized gains and losses are
currently recognized in income. Transactions related to the
interest rate swap agreements were not allocated to the
Petroleum or Nitrogen Fertilizer segments. Mark-to-market net
gains (losses) on derivatives and quarterly settlements were
$(3,791,605) and $(1,379,812) for the three and nine month
periods ended September 30, 2007, respectively.
Mark-to-market net gains (losses) on derivatives and quarterly
settlements were $(4,538,416) and $2,895,189 for the three and
nine month periods ended September 30, 2006, respectively.
|
|
(14)
|
Related
Party Transactions
|
GS Capital Partners V Fund, L.P. and related entities (GS) and
Kelso Investment Associates VII, L.P. and related entity (Kelso)
were majority owners of CALLC as of September 30, 2007.
On June 24, 2005, CALLC entered into management services
agreements with each of GS and Kelso pursuant to which GS and
Kelso agreed to provide CALLC with managerial and advisory
services. In consideration for these services, an annual fee of
$1.0 million each was paid to GS and Kelso, plus
reimbursement for any out-of-pocket expenses. The agreements had
a term ending on the date GS and Kelso ceased to own any
interests in CALLC. Relating to the agreements, $500,000 and
$1,581,849 was expensed in selling, general, and administrative
expenses (exclusive of depreciation and amortization) for the
three and nine months ended September 30, and 2007,
respectively. $518,264 and $1,566,891 were expensed in selling,
general, and administrative expense (exclusive of depreciation
and amortization) for the three and nine months ended
September 30, 2006. The agreements terminated upon
consummation of CVRs initial public offering on
October 26, 2007. The Company paid a one-time fee of
$5 million to each of GS and Kelso by reason of such
termination on October 26, 2007.
CALLC entered into certain crude oil, heating oil, and gasoline
swap agreements with a subsidiary of GS. Additional swap
agreements with this subsidiary of GS were entered into on
June 16, 2005, with an expiration date of June 30,
2010 (as described in Note 13, Derivative Financial
Instruments). Amounts totaling $44,844,669 and
$(240,861,030) were recognized related to these swap agreements
for the three and nine months ended September 30, 2007,
respectively, and are reflected in gain (loss) on derivatives.
Amounts totaling $165,810,867 and $34,174,701 were recognized
for the three and nine months ended September 30, 2006,
respectively. In addition, the consolidated balance sheet at
December 31, 2006 and September 30, 2007 includes
liabilities of $36,894,802 and $241,427,327 included in current
payable to swap counterparty and $72,806,486 and $99,202,285
included in long-term payable to swap counterparty.
On June 26, 2007, the Company entered into a letter
agreement with the subsidiary of GS to defer a
$45.0 million payment owed on July 8, 2007 to the GS
subsidiary for the period ended September 30, 2007 until
August 7, 2007. Interest accrued on the deferred amount of
$45.0 million at the rate of LIBOR plus 3.25%.
22
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As a result of the flood and the related temporary cessation of
business operations, the Company entered into a subsequent
letter agreement on July 11, 2007 in which the GS
subsidiary agreed to defer an additional $43.7 million of
the balance owed for the period ending June 30, 2007. This
deferral was entered into on the conditions that each of GS and
Kelso each agreed to guarantee one half of the payment and that
interest accrued on the $43.7 million from July 9,
2007 to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter
agreement in which the GS subsidiary agreed to defer to
September 7, 2007 both the $45.0 million payment due
August 7, 2007 along with accrued interest and the
$43.7 million payment due July 25, 2007 with the
related accrued interest. These payments were deferred on the
conditions that GS and Kelso each agreed to guarantee one half
of the payments. Additionally, interest accrues on the amount
from July 26, 2007 to the date of payment at the rate of
LIBOR plus 1.50%.
On August 23, 2007, the Company entered into an additional
letter agreement in which the GS subsidiary agreed to further
defer both deferred payment amounts and the related accrued
interest with payment being due on January 31, 2008.
Additionally, it was further agreed that the $35 million
payment to settle hedged volumes through August 15, 2007
would be deferred with payment being due on January 31,
2008. Interest accrues on all deferral amounts through the
payment due date at LIBOR plus 1.50%. GS and Kelso have each
agreed to guarantee one half of all payment deferrals. The GS
Subsidiary further agreed to defer these payment amounts to
August 31, 2008 if the Company closed an initial public
offering prior to January 31, 2008. Due to the consummation
of the initial public offering on October 26, 2007, these
payment amounts are now deferred until August 31, 2008;
however, the company is required to use 37.5% of its
consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferral amounts.
These deferred payment amounts are included in the consolidated
balance sheet at September 30, 2007 in current payable to
swap counterparty. Interest relating to the deferred payment
amounts reflected in interest expense for the three and nine
month periods ended September 30, 2007 was $1,505,950 and
$1,505,950, respectively. $1,505,950 is also included in other
current liabilities at September 30, 2007.
On August 23, 2007, the Company entered into three new
credit facilities, consisting of a $25 million secured
facility, a $25 million unsecured facility and a
$75 million unsecured facility. A subsidiary of GS was the
sole lead arranger and sole bookrunner for each of these new
credit facilities. These credit facilities and their
arrangements are more fully described in Note 9,
Long-Term Debt. The Company paid the subsidiary of
GS a $1.3 million fee included in deferred financing costs.
For both the three and nine month periods ended
September 30, 2007, interest expenses relating to these
agreements were $567,209. This amount is included in other
current liabilities at September 30, 2007. The secured and
unsecured facilities were paid in full on October 26, 2007
with proceeds from CVRs initial public offering, see
Note 1, Organization, Initial Public Offering, and
Basis of Presentation, and both facilities terminated.
Additionally, in connection with the consummation of the initial
public offering, the $75 million unsecured facility also
terminated.
On June 30, 2005, CALLC entered into three interest-rate
swap agreements with the same subsidiary of GS (as described in
Note 13, Derivative Financial Instruments).
Gains (losses) totaling $(1,893,613) and $(682,869) were
recognized related to these swap agreements for the three and
nine months ended September 30, 2007, respectively, and are
reflected in gain (loss) on derivatives. Gains (losses) totaling
$(2,280,293) and $1,441,526 were recognized related to these
swap agreements for the three and nine months ended
September 30, 2006, respectively. In addition, the
consolidated balance sheet at December 31, 2006 and
September 30, 2007 includes $1,533,738 and $443,477 in
prepaid expenses and other current assets and $2,014,504 and
$776,084 in other long-term assets related to the same
agreements, respectively.
Effective December 30, 2005, the Company entered into a
crude oil supply agreement with a subsidiary of GS (Supplier).
This agreement replaced a similar contract held with an
independent party. Both parties will negotiate the cost of each
barrel of crude oil to be purchased from a third party. CVR will
pay Supplier a fixed supply service fee per barrel over the
negotiated cost of each barrel of crude purchased. The cost is
adjusted further using a spread
23
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
adjustment calculation based on the time period the crude oil is
estimated to be delivered to the refinery, other market
conditions, and other factors deemed appropriate. The monthly
spread quantity for any delivery month at any time shall not
exceed approximately 3.1 million barrels. The initial term
of the agreement was to December 31, 2006. CVR and Supplier
agreed to extend the term of the Supply Agreement for an
additional 12 month period, January 1, 2006 through
December 31, 2007 and in connection with the extension
amended certain terms and conditions of the Supply Agreement.
$1,622,824 and $912,091 were recorded on the consolidated
balance sheet at December 31, 2006 and September 30,
2007, respectively, in prepaid expenses and other current assets
for prepayment of crude oil. In addition, $31,750,784 and
$41,644,294 were recorded in inventory and $13,458,977 and
$24,995,809 were recorded in accounts payable at
December 31, 2006 and September 30, 2007,
respectively. Expenses associated with this agreement, included
in cost of product sold (exclusive of depreciation and
amortization) for the three and nine month periods ended
September 30, 2007 totaled $249,657,118 and $765,799,978,
respectively. Expenses associated with this agreement, in cost
of product sold (exclusive of depreciation and amortization) for
the three and nine month periods ended September 30, 2006
were $444,871,411 and $1,230,270,562, respectively. Interest
expense associated with this agreement for the three and nine
month periods ended September 30, 2007 totaled $57,148 and
$(865,265), respectively.
On October 24, 2007, CVR paid a cash dividend, see
Note 16, Dividends, to its shareholders,
including approximately $5.23 million that was ultimately
distributed from CALLC II (Goldman Sachs Funds) and
approximately $5.15 million distributed from CALLC to the
Kelso Funds. Management collectively received approximately
$0.13 million.
CVR measures segment profit as operating income for Petroleum
and Nitrogen Fertilizer, CVRs two reporting segments,
based on the definitions provided in SFAS No. 131,
Disclosures About Segments of an Enterprise and Related
Information.
Petroleum
Principal products of the Petroleum Segment are refined fuels,
propane, and petroleum refining by-products including coke. CVR
uses the coke in the manufacture of nitrogen fertilizer at the
adjacent nitrogen fertilizer plant. For CVR, a $15-per-ton
transfer price is used to record intercompany sales on the part
of the Petroleum Segment and corresponding intercompany cost of
product sold (exclusive of depreciation and amortization) for
the Nitrogen Fertilizer Segment. The intercompany transactions
are eliminated in the Other Segment. Intercompany sales included
in Petroleum net sales were $679,785 and $2,560,380 for the
three and nine month periods ended September 30, 2007,
respectively. Intercompany sales included in petroleum net sales
were $1,233,255 and $3,961,995 for the three and nine month
periods ended September 30, 2006.
Nitrogen
Fertilizer
The principal products of the Nitrogen Fertilizer Segment are
anhydrous ammonia and urea ammonia nitrate solution (UAN).
Intercompany cost of product sold (exclusive of depreciation and
amortization) for the coke transfer described above was
$630,836, and $2,596,814 for the three and nine month periods
ended September 30, 2007, respectively. Intercompany cost
of product sold (exclusive of depreciation and amortization) for
the coke transfer was $1,134,167 and $3,804,870 for the three
and nine month periods ended September 30, 2006.
Other
Segment
The Other Segment reflects intercompany eliminations, cash and
cash equivalents, all debt related activities, income tax
activities and other corporate activities that are not allocated
to the operating segments.
24
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Net sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
747,296,328
|
|
|
$
|
545,901,618
|
|
|
$
|
2,204,959,676
|
|
|
$
|
1,707,343,835
|
|
Nitrogen Fertilizer
|
|
|
32,523,169
|
|
|
|
40,755,925
|
|
|
|
128,155,190
|
|
|
|
115,090,215
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment eliminations
|
|
|
(1,233,255
|
)
|
|
|
(679,785
|
)
|
|
|
(3,961,995
|
)
|
|
|
(2,560,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
778,586,242
|
|
|
$
|
585,977,758
|
|
|
$
|
2,329,152,871
|
|
|
$
|
1,819,873,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
637,506,751
|
|
|
$
|
443,081,267
|
|
|
$
|
1,828,052,007
|
|
|
$
|
1,312,150,415
|
|
Nitrogen Fertilizer
|
|
|
8,254,768
|
|
|
|
3,719,172
|
|
|
|
23,829,421
|
|
|
|
9,909,326
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
Intersegment eliminations
|
|
|
(1,134,167
|
)
|
|
|
(630,836
|
)
|
|
|
(3,804,870
|
)
|
|
|
(2,596,815
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
644,627,352
|
|
|
$
|
446,169,603
|
|
|
$
|
1,848,076,557
|
|
|
$
|
1,319,462,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
38,172,132
|
|
|
$
|
29,544,102
|
|
|
$
|
$97,254,100
|
|
|
$
|
170,684,235
|
|
Nitrogen Fertilizer
|
|
|
18,523,385
|
|
|
|
14,896,102
|
|
|
|
47,207,127
|
|
|
|
48,122,053
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
56,695,517
|
|
|
$
|
44,440,204
|
|
|
$
|
144,461,227
|
|
|
$
|
218,806,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
|
|
|
$
|
28,595,169
|
|
|
$
|
|
|
|
$
|
30,629,922
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
1,891,736
|
|
|
|
|
|
|
|
1,995,925
|
|
Other
|
|
|
|
|
|
|
1,705,437
|
|
|
|
|
|
|
|
1,705,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
32,192,342
|
|
|
$
|
|
|
|
$
|
34,331,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
7,949,815
|
|
|
$
|
6,616,389
|
|
|
$
|
23,561,843
|
|
|
$
|
29,695,304
|
|
Nitrogen Fertilizer
|
|
|
4,330,102
|
|
|
|
3,585,748
|
|
|
|
12,714,478
|
|
|
|
12,377,096
|
|
Other
|
|
|
507,619
|
|
|
|
278,928
|
|
|
|
533,323
|
|
|
|
601,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
12,787,536
|
|
|
$
|
10,481,065
|
|
|
$
|
36,809,644
|
|
|
$
|
42,673,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
55,498,485
|
|
|
$
|
26,487,906
|
|
|
$
|
233,522,252
|
|
|
$
|
129,357,929
|
|
Nitrogen Fertilizer
|
|
|
(3,007,016
|
)
|
|
|
13,833,936
|
|
|
|
34,058,010
|
|
|
|
34,863,022
|
|
Other
|
|
|
(342,575
|
)
|
|
|
(1,662,063
|
)
|
|
|
(571,233
|
)
|
|
|
(1,743,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
52,148,894
|
|
|
$
|
38,659,779
|
|
|
$
|
267,009,029
|
|
|
$
|
162,477,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
|
|
|
|
|
|
|
|
|
|
$
|
157,606,403
|
|
|
$
|
235,862,328
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
|
|
|
|
12,710,765
|
|
|
|
3,597,482
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
2,633,223
|
|
|
|
235,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
172,950,391
|
|
|
$
|
239,694,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Nine Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
907,314,951
|
|
|
$
|
1,209,530,905
|
|
Nitrogen Fertilizer
|
|
|
417,657,093
|
|
|
|
414,245,628
|
|
Other
|
|
|
124,507,471
|
|
|
|
224,791,234
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,449,479,515
|
|
|
$
|
1,848,567,767
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
42,806,422
|
|
|
$
|
42,806,422
|
|
Nitrogen Fertilizer
|
|
|
40,968,463
|
|
|
|
40,968,463
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
83,774,885
|
|
|
$
|
83,774,885
|
|
|
|
|
|
|
|
|
|
|
CVR declared a cash dividend of $0.168 per share on its common
stock to shareholders of record on October 16, 2007. The
total cash required for the dividend declared was
$10.6 million.
During the fourth quarter of 2007, a subsidiary of the Company,
CRRM, entered into an agreement for additional crude oil storage
and terminalling services with a counterparty beginning
January 1, 2008 and ending on December 31, 2014.
Average monthly commitments under this agreement for the first
nine months will approximate $124,000 with the average monthly
commitments for the remaining term increasing to approximately
$250,000. This increase results from increased storage capacity
beginning on October 1, 2008 and is subject to potential
rate acceleration. In conjunction with this agreement, the
Companys subsidiary also extended the term of its current
crude oil storage and terminalling agreement with the same
counterparty to December 31, 2014.
26
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
You should read the following discussion and analysis of our
financial condition and results of operations in conjunction
with our financial statements and related notes included
elsewhere in this report.
Forward-Looking
Statements
This
Form 10-Q,
including this managements discussion and analysis,
contains forward-looking statements as defined by
the Securities and Exchange Commission (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, 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 that 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 and
contained elsewhere in this Report.
All forward-looking statements contained in this
Form 10-Q
only speak 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.
Company
Overview
We are an independent refiner and marketer of high value
transportation fuels and a producer of ammonia and UAN
fertilizers.
We operate under two business segments: Petroleum and Nitrogen
Fertilizer. Our petroleum business includes a 113,500 bpd
complex full coking sour crude refinery in Coffeyville, Kansas.
In addition, supporting businesses include (1) a crude oil
gathering system serving central Kansas, northern Oklahoma, and
southwest Nebraska, (2) storage and terminal facilities for
asphalt and refined fuels in Phillipsburg, Kansas, and
(3) a rack marketing division supplying product through
tanker trucks directly to customers located in close geographic
proximity to Coffeyville and Phillipsburg and at throughput
terminals on 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, served by numerous pipelines
from locations including the U.S. Gulf coast and Canada,
providing us with access to virtually any crude variety in the
world capable of being transported by pipeline.
The nitrogen fertilizer 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 the lowest cost producer of ammonia and UAN in North America,
assuming natural gas prices remain at current levels. The
fertilizer plant is the only commercial facility in North
America utilizing a coke gasification
27
process to produce nitrogen fertilizers. Its redundant train
gasifier provides exceptional on-stream reliability and the use
of low cost by-product pet coke feed from the adjacent oil
refinery as feedstock (rather than natural gas) to produce
hydrogen provides the facility with a significant competitive
advantage compared to high and volatile natural gas prices. The
plants competition utilizes natural gas to produce ammonia.
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 million of CVRs outstanding term loan debt and
to repay in full the $25 million secured credit facility
and the $25 million unsecured credit facility. We also
repaid $50 million of indebtedness under our revolving
credit facility. Associated with the repayment of the
$25 million secured facility and the $25 million
unsecured facility, we expect to record a write-off of
unamortized deferred financing fees of approximately
$1.3 million in the fourth quarter of 2007.
In connection with the initial public offering, we also became
the indirect owner of Coffeyville Resources, LLC 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 stockholder 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
any restricted shares issued.
Major
Influences on Results of Operations
Petroleum Business. Our earnings and cash
flows from our petroleum operations are primarily affected by
the relationship between refined product prices and the prices
for crude oil and other feedstocks. Feedstocks are petroleum
products, such as crude oil and natural gas liquids, that are
processed and blended into refined products. The cost to acquire
feedstocks and the price for which refined products are
ultimately sold depend on factors beyond our control, including
the supply of, and demand for, crude oil, as well as gasoline
and other refined products which, in turn, depend on, among
other factors, changes in domestic and foreign economies,
weather conditions, domestic and foreign political affairs,
production levels, the availability of imports, the marketing of
competitive fuels and the extent of government regulation.
Because we apply
first-in,
first-out, or FIFO, accounting to value our inventory, crude oil
price movements may impact net income in the short term because
of instantaneous changes in the value of the minimally required,
unhedged on hand inventory. The effect of changes in crude oil
prices on our results of operations is influenced by the rate at
which the prices of refined products adjust to reflect these
changes.
Feedstock and refined product prices are also affected by other
factors, such as product pipeline capacity, local market
conditions and the operating levels of competing refineries.
Crude oil costs and the prices of refined products have,
historically, been subject to wide fluctuations. An expansion or
upgrade of our competitors facilities, price volatility,
international political and economic developments and other
factors beyond our control are likely to continue to play an
important role in refining industry economics. These factors can
impact, among other things, the level of inventories in the
market, resulting in price volatility and reduction in product
margins. Moreover, the refining industry typically experiences
seasonal fluctuations in demand for refined products, such as
increases in the demand for gasoline during the summer driving
season and for home heating oil during the winter, primarily in
the Northeast.
In order to assess our operating performance, we compare our net
sales, less cost of product sold (refining margin), against an
industry refining margin benchmark. The industry refining margin
is calculated by assuming that two barrels of benchmark light
sweet crude oil is converted into one barrel of conventional
gasoline and one barrel of distillate. This benchmark is
referred to as the 2-1-1 crack spread. Because we calculate the
benchmark margin using the market value of NYMEX gasoline and
heating oil against the market value of NYMEX WTI (WTI) crude
oil (West Texas Intermediate crude oil, which is used as a
benchmark for other crude oils), 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
28
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
distillate.
Although the 2-1-1 crack spread is a benchmark for our refinery
margin, because our refinery has certain feedstock costs
and/or
logistical advantages as compared to a benchmark refinery and
our product yield is less than total refinery throughput, the
crack spread does not account for all the factors that affect
refinery margin. Our refinery is able to process a blend of
crude oil that includes quantities of heavy and medium sour
crude oil that has historically cost less than WTI crude oil. We
measure the cost advantage of our crude oil slate by calculating
the spread between the price of our delivered crude oil to the
price of WTI crude oil, a light sweet crude oil. The spread is
referred to as our crude discount. Our refinery margin can be
impacted significantly by the consumed crude differential. Our
consumed crude differential will move directionally with changes
in the WTS differential to WTI and the Maya differential to WTI
as both these differentials indicate the relative price of
heavier, more sour, slate to WTI. The correlation between our
consumed crude differential and published differentials will
vary depending on the volume of light medium sour crude and
heavy sour crude we purchase as a percent of our total crude
volume and will correlate more closely with such published
differentials the heavier and more sour the crude oil slate.
We produce a high volume of high value products, such as
gasoline and distillates. We benefit from the fact that our
marketing region consumes more refined products than it produces
so that the market prices of our products have to be high enough
to cover the logistics cost for the U.S. Gulf Coast
refineries to ship into our region. The result of this
logistical advantage and the fact the actual product
specification used to determine the NYMEX is different from the
actual production in the refinery is that prices we realize are
different than those used in determining the 2-1-1 crack spread.
The difference between our price and the price used to calculate
the 2-1-1 crack spread is referred to as gasoline PADD II, Group
3 vs. NYMEX basis, or gasoline basis, and heating oil PADD II,
Group 3 vs. NYMEX basis, or heating oil basis.
Our direct operating expense structure is also important to our
profitability. Major direct operating expenses include energy,
employee labor, maintenance, contract labor, and environmental
compliance. Our predominant variable cost is energy which is
comprised primarily of electrical cost and natural gas.
Consistent, safe, and reliable operations at our refinery are
key to our financial performance and results of operations.
Unplanned downtime at our refinery may result in lost margin
opportunity, increased maintenance expense and a temporary
increase in working capital investment and related inventory
position.
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 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
sell at the floor price, 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.
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
29
amounts of fertilizer they apply depend on factors like crop
prices, their current liquidity, soil conditions, weather
patterns and the types of crops planted.
The value of nitrogen fertilizer products is also an important
consideration in understanding our results. The nitrogen
fertilizer business generally upgrades approximately two-thirds
of its ammonia production into UAN, a product that presently
generates a greater value than ammonia. UAN production is a
major contributor to our profitability. In order to assess the
value of nitrogen fertilizer products, we calculate netbacks,
also referred to as plant gate price. Netbacks refer to the unit
price of fertilizer, in dollars per ton, offered on a delivered
basis, excluding shipment costs.
The direct operating expense structure of the nitrogen
fertilizer business is also important to its profitability.
Using a pet coke gasification process, the nitrogen fertilizer
business has significantly higher fixed costs than natural
gas-based fertilizer plants. Major direct operating expenses
include electrical energy, employee labor, maintenance,
including contract labor, and outside services. These costs
comprise the fixed costs associated with the fertilizer plant.
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 the nitrogen fertilizer plant, which are located in close
proximity to the Verdigris River, were severely flooded,
sustained major damage and required extensive repairs. Total
costs incurred and recorded as of September 30, 2007
related to the third party costs to repair the refinery and
fertilizer facilities were approximately $71.4 million and
$3.1 million, respectively. The total third party cost to
repair the refinery is currently estimated at approximately
$86 million, and the total third party cost to repair the
nitrogen fertilizer facility is currently estimated at
approximately $4 million.
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.
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 are currently remediating the
contamination caused by the crude oil discharge. Total net costs
recorded as of September 30, 2007 associated with
remediation efforts and third party property damage incurred by
the crude oil discharge are approximately $18.1 million.
This amount is net of anticipated insurance recoveries of
$21.4 million. Subsequent to September 30, 2007, we
received $10 million of insurance proceeds under our
environmental insurance policy.
Our results for the nine months ended September 30, 2007
include pretax costs of $34.3 million associated with the
flood and related crude oil discharge. This amount is net of
anticipated insurance recoveries of $96.4 million. We
anticipate that approximately $15.5 million in third party
costs related to the repair of the flood damaged property will
be recorded in future periods.
The flood and crude oil discharge had a significant adverse
impact on our third quarter financial results. We reported
reduced revenue due to the closure of our facilities for a
portion of the third quarter, as well as significant costs
related to the flood as a result of the necessary repairs to our
facilities and environmental remediation.
Refinancing
and Prior Indebtedness
On December 28, 2006, we entered into a new credit facility
and used the proceeds thereof to repay our then existing first
lien credit facility and second lien credit facility, and to pay
a dividend to the members of Coffeyville
30
Acquisition LLC. The credit facility provides financing of up to
$1.075 billion, consisting of $775 million of
tranche D term loans, a $150 million revolving credit
facility, and a funded letter of credit facility of
$150 million issued in support of the Cash Flow Swap. The
credit facility is secured by substantially all of Coffeyville
Resources, LLCs assets. As a result, interest expense
related to the term debt outstanding of $771.1 million for
the nine months ended September 30, 2007 was significantly
higher than interest expense on term debt outstanding of
$527.8 million at September 30, 2006. Consolidated
interest expense for the nine months ended September 30,
2007 was $46.0 million as compared to interest expense of
$33.0 million for the nine months ended September 30,
2006.
The flood and crude oil discharge had a significant negative
effect on our liquidity in July/August 2007. As a result of
this, in August 2007, our subsidiaries entered into a
$25 million secured facility, a $25 million unsecured
facility and a $75 million unsecured facility. No amounts
were drawn under the $75 million unsecured facility. Our
statement of operations for the nine months ended
September 30, 2007 includes $1.1 million in interest
expense related to these facilities with no comparable amount
for the same period in the prior year.
In October 2007, we paid down $280 million of term debt
with initial public offering proceeds. Additionally, we repaid
the $25 million secured facility and $25 million
unsecured facility in their entirety with a portion of the net
proceeds from the initial public offering. Also, the
$75 million credit facility terminated upon consummation of
the initial public offering.
J. Aron
Deferrals
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, Coffeyville Resources, LLC
entered into several deferral agreements with J.
Aron & 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 January 31,
2008 the payment of approximately $123.7 million (plus
accrued interest) which we owed to J. Aron. J. Aron has agreed
to further defer these payments to August 31, 2008 but we
will be required to use 37.5% of our consolidated excess cash
flow for any quarter after January 31, 2008 to prepay the
deferred amounts.
Change in
Reporting Entity as a Result of the Initial Public
Offering
Prior to our initial public offering in October 2007, our
operations were conducted by an operating partnership,
Coffeyville Resources, LLC. The reporting entity of the
organization was also a partnership. Immediately prior to the
closing of our initial public offering, Coffeyville Resources,
LLC became an indirect, wholly-owned subsidiary of CVR Energy,
Inc. as a result of a series of steps. As a result, in the
future, we will report our results of operations and financial
condition as a corporation on a consolidated basis rather than
as an operating partnership.
Public
Company Expenses
We believe that our general and administrative expenses will
increase due to the costs of operating as a public company, such
as increases in legal, accounting and compliance, insurance
premiums, and investor relations. We estimate that the increase
in these costs will total approximately $2.5 million to
$3.0 million on an annual basis, excluding the costs
associated with the initial implementation of our Sarbanes-Oxley
Section 404 internal controls review and testing. Our
financial statements following the initial public offering will
reflect the impact of these expenses and will affect the
comparability with our financial statements of periods
subsequent to the initial public offering.
2007
Turnaround
In April 2007, we completed a planned turnaround of our refining
plant at a total cost approximating $81 million. The
majority of these costs were expensed in the first quarter of
2007. The refinery processed crude until February 11, 2007
at which time a staged shutdown of the refinery began. The
refinery recommenced operations on March 22, 2007 and
continually increased crude oil charge rates until all of the
key units were restarted by April 23, 2007. The turnaround
significantly impacted our financial results for 2007, but had
very little impact on our 2006 results.
31
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, 2006 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, 2006,
is unaudited.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Consolidated Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
778.6
|
|
|
$
|
586.0
|
|
|
$
|
2,329.2
|
|
|
$
|
1,819.9
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
644.7
|
|
|
|
446.2
|
|
|
|
1,848.1
|
|
|
|
1,319.5
|
|
Direct operating expense (exclusive of depreciation and
amortization)
|
|
|
56.7
|
|
|
|
44.4
|
|
|
|
144.5
|
|
|
|
218.8
|
|
Selling, general and administrative expense (exclusive of
depreciation and amortization)
|
|
|
12.3
|
|
|
|
14.0
|
|
|
|
32.8
|
|
|
|
42.1
|
|
Net costs associated with flood(1)
|
|
|
|
|
|
|
32.2
|
|
|
|
|
|
|
|
34.3
|
|
Depreciation and amortization(2)(3)
|
|
|
12.8
|
|
|
|
10.5
|
|
|
|
36.8
|
|
|
|
42.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
52.1
|
|
|
$
|
38.7
|
|
|
$
|
267.0
|
|
|
$
|
162.5
|
|
Other income (expense)
|
|
|
1.7
|
|
|
|
0.2
|
|
|
|
3.1
|
|
|
|
0.9
|
|
Interest (expense)
|
|
|
(10.7
|
)
|
|
|
(18.3
|
)
|
|
|
(33.0
|
)
|
|
|
(46.0
|
)
|
Gain (loss) on derivatives
|
|
|
171.2
|
|
|
|
40.5
|
|
|
|
44.7
|
|
|
|
(251.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest in
subsidiaries
|
|
$
|
214.3
|
|
|
$
|
61.1
|
|
|
$
|
281.8
|
|
|
$
|
(134.5
|
)
|
Income tax (expense) benefit
|
|
|
(85.3
|
)
|
|
|
(47.6
|
)
|
|
|
(111.0
|
)
|
|
|
93.4
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(4)
|
|
$
|
129.0
|
|
|
$
|
13.4
|
|
|
$
|
170.8
|
|
|
$
|
(40.9
|
)
|
Pro forma earnings per share, basic
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
Pro forma earnings per share, diluted
|
|
$
|
1.50
|
|
|
$
|
0.16
|
|
|
$
|
1.98
|
|
|
$
|
(0.47
|
)
|
Pro forma weighted average shares, basic
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
|
|
86,141,291
|
|
Pro forma weighted average shares, diluted
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,158,791
|
|
|
|
86,141,291
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
$
|
38.1
|
|
|
$
|
27.3
|
|
Working capital
|
|
|
|
|
|
|
|
|
|
|
173.4
|
|
|
|
(27.0
|
)
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
1,397.7
|
|
|
|
1,848.6
|
|
Total debt, including current portion
|
|
|
|
|
|
|
|
|
|
|
527.8
|
|
|
|
847.0
|
|
Minority interest in subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.2
|
|
Management units subject to compromise
|
|
|
|
|
|
|
|
|
|
|
9.0
|
|
|
|
8.7
|
|
Members equity
|
|
|
|
|
|
|
|
|
|
|
303.1
|
|
|
|
34.5
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization(3)
|
|
$
|
12.8
|
|
|
$
|
10.5
|
|
|
$
|
36.8
|
|
|
$
|
42.7
|
|
Net Income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(5)
|
|
|
21.7
|
|
|
|
(40.8
|
)
|
|
|
122.5
|
|
|
|
18.2
|
|
Cash flows (used in) provided by operating activities
|
|
|
(22.4
|
)
|
|
|
3.9
|
|
|
|
97.9
|
|
|
|
161.5
|
|
Cash flows (used in) investing activities
|
|
|
(86.8
|
)
|
|
|
(25.6
|
)
|
|
|
(173.0
|
)
|
|
|
(239.7
|
)
|
Cash flows provided by financing activities
|
|
|
19.4
|
|
|
|
26.0
|
|
|
|
48.5
|
|
|
|
63.6
|
|
Capital expenditures for property, plant and equipment
|
|
|
86.8
|
|
|
|
25.6
|
|
|
|
173.0
|
|
|
|
239.7
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (barrels per day)(6)
|
|
|
107,094
|
|
|
|
58,382
|
|
|
|
106,975
|
|
|
|
71,454
|
|
Crude oil throughput (barrels per day)(6)
|
|
|
94,019
|
|
|
|
52,497
|
|
|
|
94,061
|
|
|
|
64,829
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)
|
|
|
78.3
|
|
|
|
75.9
|
|
|
|
283.9
|
|
|
|
244.9
|
|
UAN (tons in thousands)
|
|
|
136.7
|
|
|
|
128.0
|
|
|
|
465.0
|
|
|
|
432.6
|
|
|
|
|
(1) |
|
Represents the write-off of approximate net costs associated
with the flood and oil spill that are not probable of recovery. |
|
(2) |
|
Depreciation and amortization is comprised of the following
components as excluded from cost of products sold, direct
operating expense and selling, general and administrative
expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In millions)
|
|
|
Depreciation and amortization included in cost of product sold
|
|
$
|
0.5
|
|
|
$
|
0.6
|
|
|
$
|
1.6
|
|
|
$
|
1.8
|
|
Depreciation and amortization included in direct operating
expense
|
|
|
11.7
|
|
|
|
9.6
|
|
|
|
34.5
|
|
|
|
40.2
|
|
Depreciation and amortization included in selling, general and
administrative expense
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
0.7
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
12.8
|
|
|
$
|
10.5
|
|
|
$
|
36.8
|
|
|
$
|
42.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
Depreciation and amortization does not include approximately
$7.6 million for both the three and nine months ended
September 30, 2007 which is included in net costs
associated with flood due to the facilities being temporarily
idled. |
|
(4) |
|
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 due to their
unusual or infrequent nature: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
|
|
Ended
|
|
|
Nine Months
|
|
|
|
September 30,
|
|
|
Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In millions)
|
|
|
Funded letter of credit expense and interest rate swap not
included in interest expense(a)
|
|
$
|
(0.4
|
)
|
|
$
|
0.7
|
|
|
$
|
0.2
|
|
|
$
|
0.9
|
|
Major scheduled turnaround expense(b)
|
|
|
4.1
|
|
|
|
|
|
|
|
4.4
|
|
|
|
76.8
|
|
Unrealized (gain) loss from Cash Flow Swap
|
|
|
(178.5
|
)
|
|
|
(90.2
|
)
|
|
|
(80.3
|
)
|
|
|
98.3
|
|
|
|
|
(a) |
|
Consists of fees which are expensed to selling, general and
administrative expense in connection with the funded letter of
credit facility of $150.0 million issued in support of the
Cash Flow Swap. We consider these fees to be equivalent to
interest expense and the fees are treated as such in the
calculation of EBITDA in the Credit Facility. |
|
(b) |
|
Represents expenses associated with a major scheduled turnaround
at the nitrogen fertilizer plant and our refinery. |
33
|
|
|
(5) |
|
Net income adjusted for unrealized gain or loss from Cash Flow
Swap results from adjusting for the derivative transaction that
was executed in conjunction with the acquisition of Coffeyville
Group Holdings, LLC by Coffeyville Acquisition LLC on
June 24, 2005. On June 16, 2005, Coffeyville
Acquisition LLC entered into the Cash Flow Swap with J. Aron, a
subsidiary of The Goldman Sachs Group, Inc., and a related party
of ours. The Cash Flow Swap was subsequently assigned from
Coffeyville Acquisition LLC to Coffeyville Resources, LLC on
June 24, 2005. The derivative took the form of three NYMEX
swap agreements whereby if crack spreads fall below the fixed
level, J. Aron agreed to pay the difference to us, and if crack
spreads rise above the fixed level, we agreed to pay the
difference to J. Aron. With crude oil capacity expected to reach
115,000 bpd by the end of 2007, the Cash Flow Swap
represents approximately 58% and 14% of crude oil capacity for
the periods January 1, 2008 through June 30, 2009 and
July 1, 2009 through June 30, 2010, respectively.
Under the terms of 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 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. |
|
|
|
We have determined that the Cash Flow Swap does not qualify as a
hedge for hedge accounting purposes under current GAAP. As a
result, our periodic statements of operations reflect in each
period material amounts of unrealized gains and losses based on
the increases or decreases in market value of the unsettled
position under the swap agreements which is accounted for as a
liability on our balance sheet. As the crack spreads increase we
are required to record an increase in this liability account
with a corresponding expense entry to be made to our statement
of operations. Conversely, as crack spreads decline we are
required to record a decrease in the swap related liability and
post a corresponding income entry to our statement of
operations. Because of this inverse relationship between the
economic outlook for our underlying business (as represented by
crack spread levels) and the income impact of the unrecognized
gains and losses, and given the significant periodic
fluctuations in the amounts of unrealized gains and losses,
management utilizes Net income adjusted for unrealized gain or
loss from Cash Flow Swap as a key indicator of our business
performance. In managing our business and assessing its growth
and profitability from a strategic and financial planning
perspective, management and our board of directors considers our
U.S. GAAP net income results as well as Net income adjusted for
unrealized gain or loss from Cash Flow Swap. We believe that Net
income adjusted for unrealized gain or loss from Cash Flow Swap
enhances the understanding of our results of operations by
highlighting income attributable to our ongoing operating
performance exclusive of charges and income resulting from mark
to market adjustments that are not necessarily indicative of the
performance of our underlying business and our industry. The
adjustment has been made for the unrealized loss from Cash Flow
Swap net of its related tax benefit. |
Net income adjusted for unrealized gain or loss from Cash Flow
Swap is not a recognized term under GAAP and should not be
substituted for net income as a measure of our performance but
instead should be utilized as a supplemental measure of
financial performance or liquidity in evaluating our business.
Because Net income adjusted for unrealized gain or loss from
Cash Flow Swap excludes mark to market adjustments, the measure
does not reflect the fair market value of our Cash Flow Swap in
our net income. As a result, the measure does not include
potential cash payments that may be required to be made on the
Cash Flow Swap in the future. Also, our presentation of this
non-GAAP measure may not be comparable to similarly titled
measures of other companies.
The following is a reconciliation of Net income (loss) adjusted
for unrealized gain or loss from Cash Flow Swap to Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap
|
|
$
|
21.7
|
|
|
$
|
(40.8
|
)
|
|
$
|
122.5
|
|
|
$
|
18.2
|
|
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from Cash Flow Swap, net of taxes
|
|
|
107.3
|
|
|
|
54.2
|
|
|
|
48.3
|
|
|
|
(59.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
129.0
|
|
|
$
|
13.4
|
|
|
$
|
170.8
|
|
|
$
|
(40.9
|
)
|
34
|
|
|
(6) |
|
Barrels per day is calculated by dividing the volume in the
period by the number of calendar days in the period. Barrels per
day as shown here is impacted by plant down-time and other plant
disruptions and does not represent the capacity of the
facilitys continuous operations. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
Three Months
|
|
|
Ended
|
|
|
|
Ended September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Petroleum Business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
747.3
|
|
|
$
|
545.9
|
|
|
$
|
2,205.0
|
|
|
$
|
1,707.3
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
637.5
|
|
|
|
443.1
|
|
|
|
1,828.1
|
|
|
|
1,312.2
|
|
Direct operating expense (exclusive of depreciation and
amortization)
|
|
|
38.2
|
|
|
|
29.5
|
|
|
|
97.3
|
|
|
|
170.7
|
|
Net costs associated with flood
|
|
|
|
|
|
|
28.6
|
|
|
|
|
|
|
|
30.6
|
|
Depreciation and amortization
|
|
|
7.9
|
|
|
|
6.6
|
|
|
|
23.6
|
|
|
|
29.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
63.7
|
|
|
$
|
38.1
|
|
|
$
|
256.0
|
|
|
$
|
164.1
|
|
Plus direct operating expense (exclusive of depreciation and
amortization)
|
|
|
38.2
|
|
|
|
29.5
|
|
|
|
97.3
|
|
|
|
170.7
|
|
Plus Net costs associated with flood
|
|
|
|
|
|
|
28.6
|
|
|
|
|
|
|
|
30.6
|
|
Plus depreciation and amortization
|
|
|
7.9
|
|
|
|
6.6
|
|
|
|
23.6
|
|
|
|
29.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin(1)
|
|
$
|
109.8
|
|
|
$
|
102.8
|
|
|
$
|
376.9
|
|
|
$
|
395.1
|
|
Refining margin per crude oil throughput barrel
|
|
$
|
12.69
|
|
|
$
|
21.28
|
|
|
$
|
14.68
|
|
|
$
|
22.32
|
|
Gross profit per crude oil throughput barrel
|
|
$
|
7.36
|
|
|
$
|
7.89
|
|
|
$
|
9.97
|
|
|
$
|
9.27
|
|
Direct operating expense (exclusive of depreciation and
amortization) per crude oil throughput barrel
|
|
$
|
4.42
|
|
|
$
|
6.11
|
|
|
$
|
3.79
|
|
|
$
|
9.64
|
|
Operating income (loss)
|
|
|
55.5
|
|
|
|
26.5
|
|
|
|
233.5
|
|
|
|
129.4
|
|
|
|
|
(1) |
|
Refining margin is a measurement calculated as the difference
between net sales and cost of products sold (exclusive of
depreciation and amortization). Refining margin is a non-GAAP
measure that we believe is important to investors in evaluating
our refinerys performance as a general indication of the
amount above our cost of products sold that we are able to sell
refined products. Each of the components used in this
calculation (net sales and cost of products sold exclusive of
depreciation and amortization) can be taken directly from our
statement of operations. Our calculation of refining margin may
differ from similar calculations of other companies in our
industry, thereby limiting its usefulness as a comparative
measure. |
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
Three Months Ended
|
|
|
Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
Market Indicators
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Dollars per barrel)
|
|
|
West Texas Intermediate (WTI) crude oil
|
|
$
|
70.54
|
|
|
$
|
75.15
|
|
|
$
|
68.26
|
|
|
$
|
66.19
|
|
NYMEX 2-1-1 Crack Spread
|
|
|
10.85
|
|
|
|
12.12
|
|
|
|
11.63
|
|
|
|
15.45
|
|
Crude Oil Differentials:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI less WTS (sour)
|
|
|
4.54
|
|
|
|
5.30
|
|
|
|
5.43
|
|
|
|
4.69
|
|
WTI less Maya (heavy sour)
|
|
|
14.89
|
|
|
|
12.34
|
|
|
|
15.55
|
|
|
|
11.56
|
|
WTI less Dated Brent (foreign)
|
|
|
0.99
|
|
|
|
0.52
|
|
|
|
1.33
|
|
|
|
0.89
|
|
PADD II Group 3 versus NYMEX Basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
4.00
|
|
|
|
8.93
|
|
|
|
1.82
|
|
|
|
4.74
|
|
Heating Oil
|
|
|
12.49
|
|
|
|
9.97
|
|
|
|
7.90
|
|
|
|
9.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
Company Operating Statistics
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Dollars per barrel)
|
|
|
Per barrel profit, margin and expense of crude oil throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining margin
|
|
|
12.69
|
|
|
|
21.28
|
|
|
|
14.68
|
|
|
|
22.32
|
|
Gross profit
|
|
|
7.36
|
|
|
|
7.89
|
|
|
|
9.97
|
|
|
|
9.27
|
|
Direct operating expense (exclusive of depreciation and
amortization)
|
|
|
4.42
|
|
|
|
6.11
|
|
|
|
3.79
|
|
|
|
9.64
|
|
Per gallon sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
2.11
|
|
|
|
2.28
|
|
|
|
1.99
|
|
|
|
2.14
|
|
Distillate
|
|
|
2.20
|
|
|
|
2.35
|
|
|
|
2.04
|
|
|
|
2.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
Selected Company Volumetric Data
|
|
Per Day
|
|
|
%
|
|
|
Per Day
|
|
|
%
|
|
|
Per Day
|
|
|
%
|
|
|
Per Day
|
|
|
%
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gasoline
|
|
|
41,980
|
|
|
|
39.2
|
|
|
|
25,971
|
|
|
|
44.4
|
|
|
|
46,137
|
|
|
|
43.1
|
|
|
|
29,949
|
|
|
|
41.9
|
|
Total distillate
|
|
|
39,682
|
|
|
|
37.1
|
|
|
|
23,448
|
|
|
|
40.2
|
|
|
|
41,401
|
|
|
|
38.7
|
|
|
|
29,511
|
|
|
|
41.3
|
|
Total other
|
|
|
25,432
|
|
|
|
23.7
|
|
|
|
8,963
|
|
|
|
15.4
|
|
|
|
19,437
|
|
|
|
18.2
|
|
|
|
11,994
|
|
|
|
16.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total all production
|
|
|
107,094
|
|
|
|
100.0
|
|
|
|
58,382
|
|
|
|
100.0
|
|
|
|
106,975
|
|
|
|
100.0
|
|
|
|
71,454
|
|
|
|
100.0
|
|
Crude oil throughput
|
|
|
94,019
|
|
|
|
92.3
|
|
|
|
52,497
|
|
|
|
93.9
|
|
|
|
94,061
|
|
|
|
92.6
|
|
|
|
64,829
|
|
|
|
94.7
|
|
All other inputs
|
|
|
7,831
|
|
|
|
7.7
|
|
|
|
3,403
|
|
|
|
6.1
|
|
|
|
7,463
|
|
|
|
7.4
|
|
|
|
3,643
|
|
|
|
5.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks
|
|
|
101,850
|
|
|
|
100.0
|
|
|
|
55,900
|
|
|
|
100.0
|
|
|
|
101,524
|
|
|
|
100.0
|
|
|
|
68,472
|
|
|
|
100.0
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Barrels
|
|
|
%
|
|
|
Crude oil throughput by crude type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet
|
|
|
5,466,637
|
|
|
|
63.2
|
|
|
|
2,835,032
|
|
|
|
58.7
|
|
|
|
12,916,402
|
|
|
|
50.3
|
|
|
|
11,203,099
|
|
|
|
63.3
|
|
Light/medium sour
|
|
|
3,105,258
|
|
|
|
35.9
|
|
|
|
1,168,786
|
|
|
|
24.2
|
|
|
|
12,685,293
|
|
|
|
49.4
|
|
|
|
5,256,430
|
|
|
|
29.7
|
|
Heavy sour
|
|
|
77,848
|
|
|
|
0.9
|
|
|
|
825,878
|
|
|
|
17.1
|
|
|
|
77,036
|
|
|
|
0.3
|
|
|
|
1,238,889
|
|
|
|
7.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil throughput
|
|
|
8,649,743
|
|
|
|
100.0
|
|
|
|
4,829,696
|
|
|
|
100.0
|
|
|
|
25,678,731
|
|
|
|
100.0
|
|
|
|
17,698,418
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In millions, except as otherwise indicated)
|
|
|
Nitrogen Fertilizer Business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
32.5
|
|
|
$
|
40.8
|
|
|
$
|
128.2
|
|
|
$
|
115.1
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
8.3
|
|
|
|
3.7
|
|
|
|
23.8
|
|
|
|
9.9
|
|
Direct operating expense (exclusive of depreciation and
amortization)
|
|
|
18.5
|
|
|
|
14.9
|
|
|
|
47.2
|
|
|
|
48.1
|
|
Net costs associated with flood
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
2.0
|
|
Depreciation and amortization
|
|
|
4.3
|
|
|
|
3.6
|
|
|
|
12.7
|
|
|
|
12.4
|
|
Operating income (loss)
|
|
|
(3.0
|
)
|
|
|
13.8
|
|
|
|
34.1
|
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
Market Indicators
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Natural gas (dollars per million BTU)
|
|
$
|
6.18
|
|
|
$
|
6.24
|
|
|
$
|
6.89
|
|
|
$
|
7.02
|
|
Ammonia southern plains (dollars per ton)
|
|
|
311
|
|
|
|
390
|
|
|
|
362
|
|
|
|
393
|
|
UAN corn belt (dollars per ton)
|
|
|
183
|
|
|
|
298
|
|
|
|
199
|
|
|
|
277
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
Company Operating Statistics
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
Production (thousand tons):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
78.3
|
|
|
|
75.9
|
|
|
|
283.9
|
|
|
|
244.9
|
|
UAN
|
|
|
136.7
|
|
|
|
128.0
|
|
|
|
465.0
|
|
|
|
432.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
215.0
|
|
|
|
203.9
|
|
|
|
748.9
|
|
|
|
677.5
|
|
Sales (thousand tons)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
30.6
|
|
|
|
24.7
|
|
|
|
96.8
|
|
|
|
58.8
|
|
UAN
|
|
|
138.4
|
|
|
|
120.6
|
|
|
|
477.7
|
|
|
|
414.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
169.0
|
|
|
|
145.3
|
|
|
|
574.5
|
|
|
|
473.0
|
|
Product pricing (plant gate) (dollars per ton)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ammonia
|
|
$
|
283
|
|
|
$
|
363
|
|
|
$
|
346
|
|
|
$
|
358
|
|
UAN
|
|
|
141
|
|
|
|
234
|
|
|
|
169
|
|
|
|
203
|
|
On-stream factor(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
80.7
|
%
|
|
|
81.3
|
%
|
|
|
91.7
|
%
|
|
|
87.4
|
%
|
Ammonia
|
|
|
74.2
|
%
|
|
|
80.4
|
%
|
|
|
87.8
|
%
|
|
|
84.6
|
%
|
UAN
|
|
|
76.2
|
%
|
|
|
71.8
|
%
|
|
|
87.9
|
%
|
|
|
78.5
|
%
|
Reconciliation to net sales (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Freight in revenue
|
|
$
|
4,420
|
|
|
$
|
3,581
|
|
|
$
|
13,860
|
|
|
$
|
10,011
|
|
Sales net plant gate
|
|
|
28,103
|
|
|
|
37,175
|
|
|
|
114,295
|
|
|
|
105,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net sales
|
|
|
32,523
|
|
|
|
40,756
|
|
|
|
128,155
|
|
|
|
115,091
|
|
|
|
|
(1) |
|
Plant gate sales per ton represents net sales less freight
revenue divided by sales tons. Plant gate pricing per ton is
shown in order to provide industry comparability. |
|
(2) |
|
On-stream factor is the total number of hours operated divided
by the total number of hours in the reporting period. |
Three
Months Ended September 30, 2007 Compared to the Three
Months Ended September 30, 2006
Consolidated
Net Sales. Consolidated net sales were
$586.0 million for the three months ended
September 30, 2007 compared to $778.6 million for the
three months ended September 30, 2006. The decrease of
$192.6 million for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 was primarily due to a decrease in
petroleum net sales of $201.4 million that resulted from
lower sales volumes ($301.5 million), partially offset by
higher product prices ($100.1 million). Nitrogen fertilizer
net sales increased $8.3 million for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 due to higher plant gate prices
($15.2 million), offset by lower sales volumes
($6.9 million).
Cost of Product Sold Exclusive of Depreciation and
Amortization. Consolidated cost of product sold
exclusive of depreciation and amortization was
$446.2 million for the three months ended
September 30, 2007 as compared to $644.6 million for
the three months ended September 30, 2006. The decrease of
$198.4 million for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 primarily resulted from a significant
reduction in refined fuel production volumes over the comparable
periods due to refinery downtime resulting from the flood.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Consolidated direct operating
expenses exclusive of depreciation and amortization were
$44.4 million for the three months ended September 30,
2007 as compared to $56.7 million for the three months
ended September 30, 2006. This decrease of
$12.3 million for the three months ended September 30,
2007 as compared to the three months ended September 30,
2006 was due
38
to a decrease in petroleum direct operating expenses of
$8.7 million, primarily related to decreases in expenses
associated with labor, utilities and energy due to the refinery
not operating because of the flood and the refinery turnaround,
and a decrease in nitrogen fertilizer direct operating expenses
of $3.6 million, primarily because of the turnaround
expenses incurred in the 2006 period.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization. Consolidated
selling, general and administrative expenses were
$14.0 million for the three months ended September 30,
2007 as compared to $12.3 million for the three months
ended September 30, 2006. This variance was primarily the
result of increases in administrative labor related to deferred
compensation ($3.7 million) and bank charges
($0.6 million) partially offset by reductions in expenses
associated with asset retirements ($1.1 million), outside
services ($0.9 million), public relations
($0.5 million) and office costs ($0.2 million).
Net Costs Associated with Flood. Consolidated
net costs associated with flood for the three months ended
September 30, 2007 approximated $32.2 million as
compared to none for the three months ended September 30,
2006. Total gross costs recorded for the three months ended
September 30, 2007 were approximately $128.6 million.
Of these gross costs, approximately $89.1 million were
associated with repair and other matters as a result of the
damage to the Companys facilities. Included in this cost
was $7.6 million of depreciation for the temporarily idled
facilities, $5.9 million for internal salaries,
$2.9 million of professional fees and $72.7 million
for other repair and related costs. There were approximately
$39.5 million costs recorded with respect to the
environmental remediation and property damage. Total accounts
receivable from insurers approximated $96.4 million at
September 30, 2007, for which we believe collection is
probable.
Depreciation and Amortization. Consolidated
depreciation and amortization was $10.5 million for the
three months ended September 30, 2007 as compared to
$12.8 million for the three months ended September 30,
2006. During the restoration period for both the refinery and
the nitrogen fertilizer operations due to the flood,
$7.6 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this reclassification, consolidated depreciation and
amortization would have increased by approximately
$5.3 million for the three months ended September 30,
2007 compared to the three months ended September 30, 2006,
primarily as a result of the assets placed into service during
the fourth quarter of 2006 and in 2007 resulting from the
significant capital projects we have most recently completed.
Operating Income. Consolidated operating
income was $38.7 million for the three months ended
September 30, 2007 as compared to operating income of
$52.1 million for the three months ended September 30,
2006. For the three months ended September 30, 2007 as
compared to the three months ended September 30, 2006,
petroleum operating income decreased $29.0 million and
nitrogen fertilizer operating income increased by
$16.8 million.
Interest Expense. Consolidated interest
expense for the three months ended September 30, 2007 was
$18.3 million as compared to interest expense of
$10.7 million for the three months ended September 30,
2006. This 71% increase for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 primarily resulted from an overall
increase in the index rates (primarily LIBOR) and an increase in
average borrowings outstanding during the comparable periods.
Consolidated interest expense over the comparable periods was
partially offset by decreases in the applicable margins under
our Credit Facility dated December 28, 2006 as compared to
the borrowing facility in effect during the nine months ended
September 30, 2006.
Interest Income. Interest income was
$0.2 million for the three months ended September 30,
2007 as compared to $1.1 million for the three months ended
September 30, 2006.
Gain (loss) on Derivatives. We have determined
that the Cash Flow Swap and our other derivative instruments do
not qualify as hedges for hedge accounting purposes under
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. For the three months ended
September 30, 2007, we incurred $40.5 million in gains
on derivatives. This compares to a $171.2 million gain on
derivatives for the three months ended September 30, 2006.
This significant decrease in gains on derivatives for the three
months ended September 30, 2007 as compared to the three
months ended September 30, 2006 was primarily attributable
to the realized and unrealized gains (losses) on our Cash Flow
Swap. Realized losses on the Cash Flow Swap for the three months
ended September 30, 2007 and the three months ended
September 30, 2006 were $45.4 million and
$12.7 million,
39
respectively. The increase in realized losses over the
comparable periods was primarily the result of higher average
crack spreads for the three months ended September 30, 2007
as compared to the three months ended September 30, 2006.
Unrealized gains or losses represent the change in the
mark-to-market value on the unrealized portion of the Cash Flow
Swap based on changes in the NYMEX crack spread that is the
basis for the Cash Flow Swap. Unrealized gains on our Cash Flow
Swap for the three months ended September 30, 2007 and the
three months ended September 30, 2006 were
$90.2 million and $178.5 million, respectively. These
gains reflect decreases in the crack spread values on the
unrealized positions comprising the Cash Flow Swap. In addition
to the change in the NYMEX crack spread, the outstanding term of
the Cash Flow Swap at the end of each period also affects the
impact of changes in the underlying crack spread. As of
September 30, 2007, the Cash Flow Swap had a remaining term
of approximately two years and nine months whereas as of
September 30, 2006, the remaining term on the Cash Flow
Swap was approximately three years and nine months. As a result
of the longer remaining term as of September 30, 2006, a
similar change in crack spread will have a greater impact on the
unrealized gains or losses.
Provision for Income Taxes. Income tax expense
for the three months ended September 30, 2007 was
$47.6 million, or 78% of income before income taxes, as
compared to income tax expense of $85.3 million, or 40% of
earnings before income taxes, for the three months ended
September 30, 2006. The annualized effective rate for 2007,
which was applied to loss before income taxes for the three
month period ended September 30, 2007, is higher than the
comparable annualized effective tax rate for 2006, which was
applied to earnings before income taxes for the three months
ended September 30, 2006, primarily due to the correlation
between the amount of credits which are projected to be
generated in 2007 from the production of ultra low sulfur diesel
fuel and the reduced level of projected earnings before income
taxes for 2007.
Minority Interest in (income) loss of
Subsidiaries. Minority interest in income of
subsidiaries for the three months ended September 30, 2007
was $0.1 million. Minority interest relates to common stock
in two of our subsidiaries owned by our chief executive officer.
In October 2007, in connection with our initial public offering,
our chief executive officer exchanged his common stock in our
subsidiaries for common stock of CVR Energy.
Net Income. For the three months ended
September 30, 2007, net income decreased to net income of
$13.4 million as compared to net income of
$129.0 million for the three months ended
September 30, 2006. Net income decreased
$115.6 million for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006, primarily due to downtime and costs
associated with the flood and a significant change in the value
of the Cash Flow Swap over the comparable periods.
Petroleum
Net Sales. Petroleum net sales were
$545.9 million for the three months ended
September 30, 2007 compared to $747.3 million for the
three months ended September 30, 2006. The decrease of
$201.4 million from the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 was primarily the result of
significantly lower sales volumes ($301.5 million),
partially offset by higher product prices ($100.1 million).
Overall sales volumes of refined fuels for the three months
ended September 30, 2007 decreased 39% as compared to the
three months ended September 30, 2006. The decreased sales
volume primarily resulted from a significant reduction in
refined fuel production volumes over the comparable periods due
to refinery downtime resulting from the flood. Our average sales
price per gallon for the three months ended September 30,
2007 for gasoline of $2.28 and distillate of $2.35 increased by
8% and 7%, respectively, as compared to the three months ended
September 30, 2006.
Cost of Product Sold Exclusive of Depreciation and
Amortization. Cost of product sold includes cost
of crude oil, other feedstocks and blendstocks, purchased
products for resale, transportation and distribution costs.
Petroleum cost of product sold exclusive of depreciation and
amortization was $443.1 million for the three months ended
September 30, 2007 compared to $637.5 million for the
three months ended September 30, 2006. The decrease of
$194.4 million from the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006 was primarily the result of a
significant reduction in crude throughput due to downtime
resulting from the flood. In addition to the flood, higher crude
oil prices, reduced sales volumes and the impact of FIFO
accounting also impacted cost of product sold during the
comparable periods. Our average cost per barrel of crude oil for
the three months ended September 30, 2007 was $70.93,
compared to $68.06 for the comparable period
40
of 2006, an increase of 4%. Sales volume of refined fuels
decreased 39% for the three months ended September 30, 2007
as compared to the three months ended September 30, 2006
principally due to the downtime associated with 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 three
months ended September 30, 2007, we had FIFO inventory
gains of $18.7 million compared to FIFO inventory losses of
$7.1 million for the comparable period of 2006.
Refining margin per barrel of crude throughput increased from
$12.69 for the three months ended September 30, 2006 to
$21.28 for the three months ended September 30, 2007
primarily due to the 12% increase ($1.27 per barrel) in the
average NYMEX 2-1-1 crack spread over the comparable periods and
positive regional differences between gasoline prices in our
primary marketing region (the Coffeyville supply area) and those
of the NYMEX. The average gasoline basis for the three months
ended September 30, 2007 increased by $4.93 per barrel to
$8.93 per barrel compared to $4.00 per barrel in the comparable
period of 2006. The positive basis for gasoline during the
comparable periods was partially offset by a decrease in the
average distillate basis for the three months ended
September 30, 2007 as compared to the three months ended
September 30, 2006. The average distillate basis decreased
by $2.52 per barrel to $9.97 per barrel compared to $12.49 per
barrel in the comparable period of 2006. The positive effect of
the increased NYMEX 2-1-1 crack spreads and overall refined
fuels basis over the comparable periods was further enhanced by
an increase in crude oil differential over the comparable
periods. Increased discounts for sour crude oils evidenced by
the $0.76 per barrel, or 17%, increase in the spread between the
WTI price, which is a market indicator for the price of light
sweet crude, and the WTS price, which is an indicator for the
price of sour crude, positively impacted refining margin for the
three months ended September 30, 2007 as compared to the
three months ended September 30, 2006.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Direct operating expenses for our
Petroleum operations include costs associated with the actual
operations of our refinery, such as energy and utility costs,
catalyst and chemical costs, repairs and maintenance
(turnaround), labor and environmental compliance costs.
Petroleum direct operating expenses exclusive of depreciation
and amortization were $29.5 million for the three months
ended September 30, 2007 compared to direct operating
expenses of $38.2 million for the three months ended
September 30, 2006. The decrease of $8.7 million for
the three months ended September 30, 2007 compared to the
three months ended September 30, 2006 was the result of
decreases in expenses associated with direct labor
($3.2 million), utilities and energy ($2.7 million),
refinery turnaround ($1.8 million), rent and lease
($1.7 million), operating materials ($1.4 million),
environmental ($0.7 million), repairs and maintenance
($0.7 million), production chemicals ($0.2 million)
and outside services ($0.1 million). These decreases in
direct operating expenses were partially offset by increases in
expenses associated with property taxes ($3.3 million) and
insurance ($0.6 million). On a per barrel of crude
throughput basis, direct operating expenses per barrel of crude
throughput for the three months ended September 30, 2007
increased to $6.11 per barrel as compared to $4.42 per barrel
for the three months ended September 30, 2006 principally
due to downtime at the refinery due to the flood and the
corresponding impact on overall crude oil throughput and
production volume.
Net Costs Associated with Flood. Petroleum net
costs associated with flood for the three months ended
September 30, 2007 approximated $28.6 million as
compared to none for the three months ended September 30,
2006. Total gross costs recorded for the three months ended
September 30, 2007 were approximately $121.3 million.
Of these gross costs approximately $81.8 million were
associated with repair and other matters as a result of the
damage to the refinery. Included in this cost was approximately
$6.8 million recorded for depreciation for the temporarily
idle facilities, $4.6 million for internal salaries,
$1.8 million of professional fees and $68.6 million
for other repair and related costs. There were approximately
$39.5 million recorded with respect to the environmental
remediation and property damage. Total accounts receivable from
insurers approximated $92.7 million at September 30,
2007, for which we believe collection is probable.
Depreciation and Amortization. Petroleum
depreciation and amortization was $6.6 million for the
three months ended September 30, 2007 as compared
$7.9 million for the three months ended September 30,
2006. During the restoration period for the refinery due to the
flood, $6.8 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $6.8 million reclassification, the increase in
petroleum depreciation and amortization for the three months
ended September 30, 2007 compared to the three
41
months ended September 30, 2006 would have been
approximately $5.5 million. This adjusted increase in
petroleum depreciation and amortization for the three months
ended September 30, 2007 as compared to the three months
ended September 30, 2006 was primarily the result of the
completion of the several large capital projects in late 2006
and during the nine months ended September 30, 2007.
Operating Income. Petroleum operating income
was $26.5 million for the three months ended
September 30, 2007 as compared to operating income of
$55.5 million for the three months ended September 30,
2006. This decrease of $29.0 million from the three months
ended September 30, 2007 as compared to the three months
ended September 30, 2006 was primarily the result of the
refinery downtime resulting from the flood and the
$28.6 million increase in net costs associated with the
flood. Substantially all of the refinerys units damaged by
the flood were back in operation by August 20, 2007.
Offsetting the negative impacts of the flood was an
$8.7 million reduction in direct operating expenses for the
three months ended September 30, 2007 compared to the three
months ended September 30, 2006. This reduction was the
result of decreases in expenses associated with direct labor
($3.2 million), utilities and energy ($2.7 million),
refinery turnaround ($1.8 million), rent and lease
($1.7 million), operating materials ($1.4 million),
environmental ($0.7 million), repairs and maintenance
($0.7 million), production chemicals ($0.2 million)
and outside services ($0.1 million). These decreases in
direct operating expenses were partially offset by increases in
expenses associated with taxes ($3.3 million) and insurance
($0.6 million).
Fertilizer
Net Sales. Nitrogen fertilizer net sales were
$40.8 million for the three months ended September 30,
2007 compared to $32.5 million for the three months ended
September 30, 2006. The increase of $8.3 million for
the three months ended September 30, 2007 as compared to
the three months ended September 30, 2006 was the result of
higher plant gate prices ($15.2 million), offset by
reductions in overall sales volume ($6.9 million).
In regard to product sales volumes for the three months ended
September 30, 2007, our nitrogen operations experienced a
decrease of 19% in ammonia sales unit volumes (5,918 tons) and a
decrease of 13% in UAN sales unit volumes (17,835 tons). The
decrease in ammonia sales volume was the result of decreased
production volumes during the three months ended
September 30, 2007 relative to the comparable period of
2006 due to the transfer of hydrogen to our Petroleum operations
to facilitate sulfur recovery in the ultra low sulfur diesel
production unit. The transfer of hydrogen to our Petroleum
operations is scheduled to be replaced with hydrogen produced by
the new continuous catalytic reformer scheduled to be completed
in late 2007 to early 2008. On-stream factors (total number of
hours operated divided by total hours in the reporting period)
for the gasification and ammonia units were greater than the
three months ended September 30, 2006. On-stream factors
for the UAN plant were lower than the three month period ended
September 30, 2006. 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. On-stream factors for the
three months ended September 30, 2006 were negatively
impacted by a major scheduled turnaround at the nitrogen
fertilizer plant and unscheduled downtime associated with
repairs and maintenance to the ammonia plant. 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 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, 2007 for ammonia and
UAN were greater than plant gate prices for the comparable
period of 2006 by 28% and 66%, respectively. This dramatic
increase in nitrogen fertilizer prices was not the result of an
increase in natural gas prices, but rather the result of
increased demand for nitrogen-based fertilizers due to the
increased use of corn for the production of ethanol and an
overall increase in prices for corn, wheat and soybeans, the
primary row crops in our region. This increase in demand for
nitrogen-based fertilizer has created an environment in which
nitrogen fertilizer prices have disconnected from their
traditional correlation to natural gas prices.
42
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
petroleum coke expense, hydrogen reimbursement and freight and
distribution expenses. Cost of product sold excluding
depreciation and amortization for the three months ended
September 30, 2007 was $3.7 million compared to
$8.3 million for the three months ended September 30,
2006. The decrease of $4.6 million for the three months
ended September 30, 2007 as compared to the three months
ended September 30, 2006 was primarily the result of
increased hydrogen reimbursement due to the transfer of hydrogen
to our Petroleum operations to facilitate sulfur recovery in the
ultra low sulfur diesel production unit and reduced freight
expense partially offset by an increase in petroleum coke costs.
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, 2007 were $14.9 million as compared to
$18.5 million for the three months ended September 30,
2006. The decrease of $3.6 million for the three months
ended September 30, 2007 as compared to the three months
ended September 30, 2006 was primarily the result of
decreases in expenses associated with turnaround
($2.3 million), outside services ($0.6 million),
royalties and other ($0.5 million), utilities
($0.2 million), labor ($0.1 million) and chemicals
($0.1 million). These decreases in direct operating
expenses were partially offset by increases in expenses
associated with repairs and maintenance ($0.4 million).
Net Costs Associated with Flood. Nitrogen
fertilizer net costs associated with flood for the three months
ended September 30, 2007 approximated $1.9 million as
compared to none for the three months ended September 30,
2006. Total gross costs recorded as a result of the damage to
the fertilizer plant for the three months ended
September 30, 2007 were approximately $5.1 million.
Included in this cost was approximately $0.8 million
recorded for depreciation for the temporarily idle facilities,
$0.7 million for internal salaries and $3.6 million
for other repair and related costs. Total accounts receivable
from insurers approximated $3.2 million at
September 30, 2007, for which we believe collection is
probable.
Depreciation and Amortization. Nitrogen
fertilizer depreciation and amortization decreased to
$3.6 million for the three months ended September 30,
2007 as compared to $4.3 million for the three months ended
September 30, 2006. During the restoration period for the
nitrogen fertilizer operations due to the flood,
$0.8 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $0.8 million reclassification, nitrogen fertilizer
depreciation and amortization would have increased by
approximately $0.1 million for the three months ended
September 30, 2007 compared to the three months ended
September 30, 2006.
Operating Income. Nitrogen fertilizer
operating income was $13.8 million for the three months
ended September 30, 2007 as compared to an operating loss
of $3.0 million for the three months ended
September 30, 2006. This increase of $16.8 million for
the three months ended September 30, 2007 as compared to
the three months ended September 30, 2006 was primarily the
result of increased fertilizer prices over the comparable
periods and a $4.6 million reduction in cost of product
sold excluding depreciation and amortization due to increased
hydrogen reimbursement and reduced freight expense partially
offset by an increase in petroleum coke costs. Additionally,
decreased direct operating expenses associated with turnaround
($2.3 million), outside services ($0.6 million),
royalties and other ($0.5 million), utilities
($0.2 million), labor ($0.1 million) and chemicals
($0.1 million) also contributed to the positive operating
income comparison over the comparable periods. These decreases
in expenses were partially offset by reduced sales volumes and
increased direct operating expenses primarily the result of
increases in repairs and maintenance ($0.4 million).
43
Nine
Months Ended September 30, 2007 Compared to the Nine Months
Ended September 30, 2006.
Consolidated
Net Sales. Consolidated net sales were
$1,819.9 million for the nine months ended
September 30, 2007 compared to $2,329.2 million for
the nine months ended September 30, 2006. The decrease of
$509.3 million for the nine months ended September 30,
2007 as compared to the nine months ended September 30,
2006 was primarily due to a decrease in petroleum net sales of
$497.7 million that resulted from lower sales volumes
($656.8 million), partially offset by higher product prices
($159.1 million). Nitrogen fertilizer net sales decreased
$13.1 million for the nine months ended September 30,
2007 as compared to the nine months ended September 30,
2006 due to lower sales volumes ($28.6 million), partially
offset by higher plant gate prices ($15.5 million).
Cost of Product Sold Exclusive of Depreciation and
Amortization. Consolidated cost of product sold exclusive of
depreciation and amortization was $1,319.5 million for the
nine months ended September 30, 2007 as compared to
$1,848.1 million for the nine months ended
September 30, 2006. The decrease of $528.6 million for
the nine months ended September 30, 2007 as compared to the
nine months ended September 30, 2006 primarily resulted
from a significant reduction in refined fuel production volumes
over the comparable periods due to the refinery turnaround which
began in February 2007 and was completed in April 2007 and the
refinery downtime resulting from the flood.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Consolidated direct operating
expenses exclusive of depreciation and amortization were
$218.8 million for the nine months ended September 30,
2007 as compared to $144.5 million for the nine months
ended September 30, 2006. This increase of
$74.3 million for the nine months ended September 30,
2007 as compared to the nine months ended September 30,
2006 was due to an increase in petroleum direct operating
expenses of $73.4 million, primarily related to the
refinery turnaround, and an increase in nitrogen fertilizer
direct operating expenses of $0.9 million.
Selling, General and Administrative Expenses Exclusive of
Depreciation and Amortization. Consolidated
selling, general and administrative expenses exclusive of
depreciation and amortization were $42.1 million for the
nine months ended September 30, 2007 as compared to
$32.8 million for the nine months ended September 30,
2006. This variance was primarily the result of increases in
administrative labor primarily related to deferred compensation
($9.2 million), other costs ($0.7 million), bank
charges ($0.6 million) and office costs ($0.3 million)
partially offset by reductions in expenses associated with asset
retirements ($1.1 million).
Net Costs Associated with Flood. Consolidated
net costs associated with flood for the nine months ended
September 30, 2007 approximated $34.3 million as
compared to none for the nine months ended September 30,
2006. Total gross costs recorded for the nine months ended
September 30, 2007 were approximately $130.7 million.
Of these gross costs, approximately $91.2 million were
associated with repair and other matters as a result of the
damage to the Companys facilities. Included in this cost
was $7.6 million of depreciation for the temporarily idled
facilities, $5.9 million for internal salaries,
$2.9 million of professional fees and $74.8 million
for other repair and related costs. There were approximately
$39.5 million costs recorded with respect to the
environmental remediation and property damage. Total accounts
receivable from insurers approximated $96.4 million at
September 30, 2007, for which we believe collection is
probable.
Depreciation and Amortization. Consolidated
depreciation and amortization was $42.7 million for the
nine months ended September 30, 2007 as compared to
$36.8 million for the nine months ended September 30,
2006. During the restoration period for the refinery and our
nitrogen fertilizer operations due to the flood,
$7.6 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $7.6 million reclassification, the increase in
consolidated depreciation and amortization for the nine months
ended September 30, 2007 compared to the nine months ended
September 30, 2006 would have been approximately
$13.5 million. This adjusted increase in consolidated
depreciation and amortization for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 was primarily the result of the
completion of the several large capital projects in late 2006
and during the nine months ended September 30, 2007 in our
Petroleum business
Operating Income. Consolidated operating
income was $162.5 million for the nine months ended
September 30, 2007 as compared to operating income of
$267.0 million for the nine months ended September 30,
2006. For
44
the nine months ended September 30, 2007 as compared to the
nine months ended September 30, 2006, petroleum operating
income decreased $104.1 million and nitrogen fertilizer
operating income increased by $0.8 million.
Interest Expense. Consolidated interest
expense for the nine months ended September 30, 2007 was
$46.0 million as compared to interest expense of
$33.0 million for the nine months ended September 30,
2006. This 39% increase for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 primarily resulted from an overall
increase in the index rates (primarily LIBOR) and an increase in
average borrowings outstanding during the comparable periods.
Partially offsetting these negative impacts on consolidated
interest expense was a $1.7 million increase in capitalized
interest over the comparable periods due to the increase of
capital projects in progress during the nine months ended
September 30, 2007. Additionally, consolidated interest
expense over the comparable periods was partially offset by
decreases in the applicable margins under our Credit Facility
dated December 28, 2006 as compared to our borrowing
facility in effect during the nine months ended
September 30, 2006.
Interest Income. Interest income was
$0.8 million for the nine months ended September 30,
2007 as compared to $2.8 million for the nine months ended
September 30, 2006.
Gain (loss) on Derivatives. We have determined
that the Cash Flow Swap and our other derivative instruments do
not qualify as hedges for hedge accounting purposes under
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. For the nine months ended
September 30, 2007, we incurred $251.9 million in
losses on derivatives. This compares to a $44.7 million
gain on derivatives for the nine months ended September 30,
2006. This significant change in gain (loss) on derivatives for
the nine months ended September 30, 2007 as compared to the
nine months ended September 30, 2006 was primarily
attributable to the realized and unrealized gains (losses) on
our Cash Flow Swap. Realized losses on the Cash Flow Swap for
the nine months ended September 30, 2007 and the nine
months ended September 30, 2006 were $142.6 million
and $46.2 million, respectively. The increase in realized
losses over the comparable periods was primarily the result of
higher average crack spreads for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006. Unrealized gains or losses represent
the change in the mark-to-market value on the unrealized portion
of the Cash Flow Swap based on changes in the NYMEX crack spread
that is the basis for the Cash Flow Swap. Unrealized losses on
our Cash Flow Swap for the nine months ended September 30,
2007 were $98.3 million and reflect an increase in the
crack spread values on the unrealized positions comprising the
Cash Flow Swap. In contrast, the unrealized portion of the Cash
Flow Swap for the nine months ended September 30, 2006
reported mark-to-market gains of $80.3 million and reflect
a decrease in the crack spread values on the unrealized
positions comprising the Cash Flow Swap. In addition, the
outstanding term of the Cash Flow Swap at the end of each period
also affects the impact of changes in the underlying crack
spread. As of September 30, 2007, the Cash Flow Swap had a
remaining term of approximately two years and nine months
whereas as of September 30, 2006, the remaining term on the
Cash Flow Swap was approximately three years and nine months. As
a result of the longer remaining term as of September 30,
2006, a similar change in crack spread will have a greater
impact on the unrealized gains or losses.
Provision for Income Taxes. Income tax benefit
for the nine months ended September 30, 2007 was
$93.4 million, or 69% of loss before income taxes, as
compared to income tax expense of $111.0 million, or 39% of
earnings before income taxes, for the nine months ended
September 30, 2006. The annualized effective rate for 2007,
which was applied to loss before income taxes for the nine month
period ended September 30, 2007, is higher than the
comparable annualized effective tax rate for 2006, which was
applied to earnings before income taxes for the nine months
ended September 30, 2006, primarily due to the correlation
between the amount of credits which are projected to be
generated in 2007 from the production of ultra low sulfur diesel
fuel and the reduced level of projected earnings before income
taxes for 2007.
Minority Interest in (income) loss of
Subsidiaries. Minority interest in loss of
subsidiaries for the nine months ended September 30, 2007
was $0.2 million. Minority interest relates to common stock
in two of our subsidiaries owned by our chief executive officer.
In October 2007, in connection with our initial public offering,
our chief executive officer exchanged his common stock in our
subsidiaries for common stock of CVR Energy.
Net Income. For the nine months ended
September 30, 2007, net income decreased to a net loss of
$40.9 million as compared to net income of
$170.8 million for the nine months ended September 30,
2006.
45
Net income decreased $211.7 million for the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006, primarily due to the refinery
turnaround, downtime and costs associated with the flood and a
significant change in the value of the Cash Flow Swap over the
comparable periods.
Petroleum
Net Sales. Petroleum net sales were
$1,707.3 million for the nine months ended
September 30, 2007 compared to $2,205.0 million for
the nine months ended September 30, 2006. The decrease of
$497.7 million from the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 was primarily the result of
significantly lower sales volumes ($656.8 million),
partially offset by higher product prices ($159.1 million).
Overall sales volumes of refined fuels for the nine months ended
September 30, 2007 decreased 29% as compared to the nine
months ended September 30, 2006. The decreased sales volume
primarily resulted from a significant reduction in refined fuel
production volumes over the comparable periods due to the
refinery turnaround which began in February 2007 and was
completed in April 2007 and the refinery downtime resulting from
the flood. Our average sales price per gallon for the nine
months ended September 30, 2007 for gasoline of $2.14 and
distillate of $2.12 increased by 8% and 4%, respectively, as
compared to the nine months ended September 30, 2006.
Cost of Product Sold Exclusive of Depreciation and
Amortization. Cost of product sold includes cost
of crude oil, other feedstocks and blendstocks, purchased
products for resale, transportation and distribution costs.
Petroleum cost of product sold exclusive of depreciation and
amortization was $1,312.2 million for the nine months ended
September 30, 2007 compared to $1,828.1 million for
the nine months ended September 30, 2006. The decrease of
$515.9 million from the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 was primarily the result of a
significant reduction in crude throughput due to the refinery
turnaround which began in February 2007 and was completed in
April 2007 and the refinery downtime resulting from the flood.
In addition to the refinery turnaround and the flood, crude oil
prices, reduced sales volumes and the impact of FIFO accounting
also impacted cost of product sold during the comparable
periods. Our average cost per barrel of crude oil for the nine
months ended September 30, 2007 was $60.90, compared to
$63.87 for the comparable period of 2006, a decrease of 5%.
Sales volume of refined fuels decreased 29% for the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006 principally due to the refinery
turnaround and flood. In addition, under our FIFO accounting
method, changes in crude oil prices can cause fluctuations in
the inventory valuation of our crude oil, work in process and
finished goods, thereby resulting in FIFO inventory gains when
crude oil prices increase and FIFO inventory losses when crude
oil prices decrease. For the nine months ended
September 30, 2007, we had FIFO inventory gains of
$37.4 million compared to FIFO inventory gains of
$13.0 million for the comparable period of 2006.
Refining margin per barrel of crude throughput increased from
$14.68 for the nine months ended September 30, 2006 to
$22.32 for the nine months ended September 30, 2007
primarily due to the 33% increase ($3.82 per barrel) in the
average NYMEX 2-1-1 crack spread over the comparable periods and
positive regional differences between gasoline and distillate
prices in our primary marketing region (the Coffeyville supply
area) and those of the NYMEX. The average gasoline basis for the
nine months ended September 30, 2007 increased by $2.92 per
barrel to $4.74 per barrel compared to $1.82 per barrel in the
comparable period of 2006. The average distillate basis for the
nine months ended September 30, 2007 increased by $1.64 per
barrel to $9.54 per barrel compared to $7.90 per barrel in the
comparable period of 2006. The positive effect of the increased
NYMEX 2-1-1 crack spreads and refined fuels basis over the
comparable periods was partially offset by reductions in the
crude oil differentials over the comparable periods. Decreased
discounts for sour crude oils evidenced by the $0.74 per barrel,
or 14%, decrease in the spread between the WTI price, which is a
market indicator for the price of light sweet crude, and the WTS
price, which is an indicator for the price of sour crude,
negatively impacted refining margin for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006.
Direct Operating Expenses Exclusive of Depreciation and
Amortization. Direct operating expenses for our Petroleum
operations include costs associated with the actual operations
of our refinery, such as energy and utility costs, catalyst and
chemical costs, repairs and maintenance (turnaround), labor and
environmental compliance costs. Petroleum direct operating
expenses exclusive of depreciation and amortization were
$170.7 million for the nine months ended September 30,
2007 compared to direct operating expenses of $97.3 million
for the nine months
46
ended September 30, 2006. The increase of
$73.4 million for the nine months ended September 30,
2007 compared to the nine months ended September 30, 2006
was the result of increases in expenses associated with repairs
and maintenance related to the refinery turnaround
($74.9 million), taxes ($6.8 million), insurance
($1.9 million), direct labor ($1.3 million), outside
services ($1.2 million) and production chemicals
($0.4 million). These increases in direct operating
expenses were partially offset by reductions in expenses
associated with energy and utilities ($5.8 million),
repairs and maintenance ($3.0 million), environmental
compliance ($2.4 million), rent and lease
($1.7 million) and operating materials ($0.6 million).
On a per barrel of crude throughput basis, direct operating
expenses per barrel of crude throughput for the nine months
ended September 30, 2007 increased to $9.64 per barrel as
compared to $3.79 per barrel for the nine months ended
September 30, 2006 principally due to refinery turnaround
expenses and the related downtime associated with the turnaround
and the flood and the corresponding impact on overall crude oil
throughput and production volume.
Net Costs Associated with Flood. Petroleum net
costs associated with the flood for the nine months ended
September 30, 2007 approximated $30.6 million as
compared to none for the nine months ended September 30,
2006. Total gross costs recorded for the nine months ended
September 30, 2007 were approximately $123.3 million.
Of these gross costs approximately $83.8 million were
associated with repair and other matters as a result of the
damage to the refinery. Included in this cost was approximately
$6.8 million recorded for depreciation for the temporarily
idle facilities, $4.6 million for internal salaries,
$1.8 million of professional fees and $70.6 million
for other repair and related costs. There were approximately
$39.5 million recorded with respect to the environmental
remediation and property damage. Total accounts receivable from
insurers approximated $92.7 million at September 30,
2007, for which we believe collection is probable.
Depreciation and Amortization. Petroleum
depreciation and amortization was $29.7 million for the
nine months ended September 30, 2007 as compared
$23.6 million for the nine months ended September 30,
2006, an increase of $6.1 million over the comparable
periods. During the restoration period for the refinery due to
the flood, $6.8 million of depreciation and amortization
was reclassified into net costs associated with flood. Adjusting
for this $6.8 million reclassification, the increase in
petroleum depreciation and amortization for the nine months
ended September 30, 2007 compared to the nine months ended
September 30, 2006 would have been approximately
$12.9 million. This adjusted increase in petroleum
depreciation and amortization for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 was primarily the result of the
completion of the several large capital projects in late 2006
and during the nine months ended September 30, 2007.
Operating Income. Petroleum operating income
was $129.4 million for the nine months ended
September 30, 2007 as compared to operating income of
$233.5 million for the nine months ended September 30,
2006. This decrease of $104.1 million from the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006 was primarily the result of the
refinery turnaround which began in February 2007 and was
completed in April 2007 and the refinery downtime resulting from
the flood. The turnaround negatively impacted daily refinery
crude throughput and refined fuels production. Substantially all
of the refinerys units damaged by the flood were back in
operation by August 20, 2007. In addition, direct operating
expenses increased substantially during the nine months ended
September 30, 2007 related to repairs and maintenance
associated with the refinery turnaround ($74.9 million),
taxes ($6.8 million), insurance ($1.9 million), direct
labor ($1.3 million), outside services ($1.2 million)
and production chemicals ($0.4 million). These increases in
direct operating expenses were partially offset by reductions in
expenses associated with energy and utilities
($5.8 million), repairs and maintenance
($3.0 million), environmental compliance
($2.4 million), rent and lease ($1.7 million) and
operating materials ($0.6 million).
Fertilizer
Net Sales. Nitrogen fertilizer net sales were
$115.1 million for the nine months ended September 30,
2007 compared to $128.2 million for the nine months ended
September 30, 2006. The decrease of $13.1 million from
the nine months ended September 30, 2007 as compared to the
nine months ended September 30, 2006 was the result of
reductions in overall sales volumes ($28.6 million),
partially offset by higher plant gate prices
($15.5 million).
In regard to product sales volumes for the nine months ended
September 30, 2007, our nitrogen operations experienced a
decrease of 39% in ammonia sales unit volumes (38,076 tons) and
a decrease of 13% in UAN sales
47
unit volumes (63,542 tons). The decrease in ammonia sales volume
was the result of decreased production volumes during the nine
months ended September 30, 2007 relative to the comparable
period of 2006 due to unscheduled downtime at our fertilizer
plant and the transfer of hydrogen to our Petroleum operations
to facilitate sulfur recovery in the ultra low sulfur diesel
production unit. The transfer of hydrogen to our Petroleum
operations is scheduled to be replaced with hydrogen produced by
the new continuous catalytic reformer scheduled to be completed
in the late 2007 to early 2008. On-stream factors (total number
of hours operated divided by total hours in the reporting
period) for all units of our nitrogen operations (gasifier,
ammonia plant and UAN plant) were less than the comparable
period primarily due to approximately eighteen days of downtime
for all three primary nitrogen units associated with the flood
and nine days of downtime related to compressor repairs in the
ammonia unit In addition, all three primary units also
experienced brief and unscheduled downtime for repairs and
maintenance during the nine months ended September 30,
2007. It is typical to experience brief outages in complex
manufacturing operations such as our nitrogen fertilizer plant
which result in less than one hundred percent on-stream
availability for one or more specific units.
Plant gate prices are prices FOB the delivery point less any
freight cost we absorb to deliver the product. We believe plant
gate price is meaningful because we sell products both FOB our
plant gate (sold plant) and FOB the customers designated
delivery site (sold delivered) and the percentage of sold plant
versus sold delivered can change month to month or nine months
to nine 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, 2007 for ammonia and
UAN were greater than plant gate prices for the comparable
period of 2006 by 3% and 20%, respectively. Our ammonia and UAN
sales prices for product shipped during the nine months ended
September 30, 2006 generally followed volatile natural gas
prices; however, it is typical for the reported pricing in our
fertilizer business to lag the spot market prices for nitrogen
fertilizer due to forward price contracts. As a result, forward
price contracts entered into the late summer and fall of 2005
(during a period of relatively high natural gas prices due to
the impact of hurricanes Rita and Katrina) comprised a
significant portion of the product shipped in the spring of
2006. However, as natural gas prices moderated in the spring and
summer of 2006, fertilizer nitrogen fertilizer prices declined
and the spot and fill contracts entered into and shipped during
this lower natural gas prices environment realized lower average
netbacks. Ammonia and UAN sales prices for the nine months
ending September 2007 were impacted by both relatively low
natural gas prices and a dramatic increase in nitrogen
fertilizer prices driven by increased demand for fertilizer due
to the increased use of corn for the production of ethanol and
an overall increase in prices for corn, wheat and soybeans, the
primary row crops in our region. This increase in demand for
nitrogen fertilizer has created an environment in which nitrogen
fertilizer prices have disconnected from their traditional
correlation to natural gas.
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
petroleum coke expense, hydrogen reimbursement and freight and
distribution expenses. Cost of product sold excluding
depreciation and amortization for the nine months ended
September 30, 2007 was $9.9 million compared to
$23.8 million for the nine months ended September 30,
2006. The decrease of $13.9 million for the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006 was primarily the result of
increased hydrogen reimbursement due to the transfer of hydrogen
to our Petroleum operations to facilitate sulfur recovery in the
ultra low sulfur diesel production unit and reduced freight
expense partially offset by an increase in petroleum coke costs.
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, 2007 were $48.1 million as compared to
$47.2 million for the nine months ended September 30,
2006. The increase of $0.9 million for the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006 was primarily the result of
increases in repairs and maintenance
48
($3.6 million), utilities ($1.0 million), equipment
rental ($0.4 million), and insurance ($0.3 million).
These increases in direct operating expenses were partially
offset by reductions in expenses associated with turnaround
($2.6 million), royalties ($0.6 million), catalyst
($0.5 million), outside services ($0.3 million) and
chemicals ($0.3 million).
Net Costs Associated with Flood. Nitrogen
fertilizer net costs associated with flood for the nine months
ended September 30, 2007 approximated $2.0 million as
compared to none for the nine months ended September 30,
2006. Total gross costs recorded as a result of the damage to
the fertilizer plant for the nine months ended
September 30, 2007 were approximately $5.2 million.
Included in this cost was approximately $0.8 million
recorded for depreciation for the temporarily idle facilities,
$0.7 million for internal salaries and $3.7 million
for other repair and related costs. Total accounts receivable
from insurers approximated $3.2 million at
September 30, 2007, for which we believe collection is
probable.
Depreciation and Amortization. Nitrogen
fertilizer depreciation and amortization decreased to
$12.4 million for the nine months ended September 30,
2007 as compared to $12.7 million for the nine months ended
September 30, 2006. During the restoration period for the
nitrogen fertilizer operations due to the flood,
$0.8 million of depreciation and amortization was
reclassified into net costs associated with flood. Adjusting for
this $0.8 reclassification, nitrogen fertilizer depreciation and
amortization would have increased by approximately
$0.5 million for the nine months ended September 30,
2007 compared to the nine months ended September 30, 2006.
Operating Income. Nitrogen fertilizer
operating income was $34.9 million for the nine months
ended September 30, 2007 as compared to $34.1 million
for the nine months ended September 30, 2006. This increase
of $0.8 million for the nine months ended
September 30, 2007 as compared to the nine months ended
September 30, 2006 was primarily the result of a
$13.9 million reduction in cost of product sold excluding
depreciation and amortization due to increased hydrogen
reimbursement and reduced freight expense partially offset by an
increase in petroleum coke costs and decreased direct operating
expenses associated with turnaround ($2.6 million),
royalties ($0.6 million), catalyst ($0.5 million),
outside services ($0.3 million) and chemicals
($0.3 million). These decreases in expenses were partially
offset by reduced sales volumes and increased direct operating
expenses primarily the result of increases in repairs and
maintenance ($3.6 million), utilities ($1.0 million),
equipment rental ($0.4 million) and insurance
($0.3 million).
Liquidity
and Capital Resources
Our primary sources of liquidity are cash generated from our
operating activities, existing cash balances and our existing
revolving credit facility. Additionally, we have borrowings from
related parties. 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.
Our liquidity was enhanced during the fourth quarter of 2007 by
the receipt of $408.5 million of net proceeds from our
initial public offering after the payment of underwriting
discounts and commissions, but before the deduction of offering
expenses. We believe that our cash flows from operations,
borrowings under our revolving credit facilities, proceeds from
the initial public offering 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. Additionally, our ability to
generate sufficient cash from our operating activities depends
on our future performance, which is subject to general economic,
political, financial, competitive, and other factors beyond our
control.
Debt
Credit
Facility
On December 28, 2006, our subsidiary Coffeyville Resources,
LLC 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
49
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, 2007,
we had available $93.1 million under the revolving credit
facility. As of October 26, 2007, after giving effect to
our initial public offering, we had available
$110.6 million under the revolving credit facility.
The $150.0 million funded letter of credit facility
provides credit support for our obligations under the Cash Flow
Swap. The funded letter of credit facility is fully cash
collateralized by the funding by the lenders of cash into a
credit linked deposit account. This account is held by the
funded letter of credit issuing bank. Contingent upon the
requirements of the Cash Flow Swap, the borrower has the ability
to reduce the funded letter of credit at any time upon written
notice to the lenders. The funded letter of credit facility
expires on December 28, 2010.
The Credit Facility incorporates the following pricing by
facility type:
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Tranche D term loans bear interest at either (a) the
greater of the prime rate and the federal funds effective rate
plus 0.5%, plus in either case 2.25%, or, at the borrowers
option, (b) LIBOR plus 3.25% (with
step-downs
to the prime rate/federal funds rate plus 1.75% or 1.50% or
LIBOR plus 2.75% or 2.50%, respectively, upon achievement of
certain rating conditions).
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Revolving loan borrowings bear interest at either (a) the
greater of the prime rate and the federal funds effective rate
plus 0.5%, plus in either case 2.25%, or, at the borrowers
option, (b) LIBOR plus 3.25% (with step-downs to the prime
rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75%
or 2.50%, respectively, upon achievement of certain rating
conditions).
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Letters of credit issued under the $75.0 million sub-limit
available under the revolving loan facility are subject to a fee
equal to the applicable margin on revolving LIBOR loans owing to
all revolving lenders and a fronting fee of 0.25% per annum
owing to the issuing lender.
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Funded letters of credit are subject to a fee equal to the
applicable margin on term LIBOR loans owed to all funded letter
of credit lenders and a fronting fee of 0.125% per annum owing
to the issuing lender. The borrower is also obligated to pay a
fee of 0.10% to the administrative agent on a quarterly basis
based on the average balance of funded letters of credit
outstanding during the calculation period, for the maintenance
of a credit-linked deposit account backstopping funded letters
of credit.
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In addition to the fees stated above, the Credit Facility
requires the borrower to pay 0.50% per annum in commitment fees
on the unused portion of the revolving loan facility.
The Credit Facility requires the borrower to prepay outstanding
loans, subject to certain exceptions, with:
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100% of the net asset sale proceeds received from specified
asset sales and net insurance/condemnation proceeds, if the
borrower does not reinvest those proceeds in assets to be used
in its business or make other permitted investments within
12 months or if, within 12 months of receipt, the
borrower does not contract to reinvest those proceeds in assets
to be used in its business or make other permitted investments
within 18 months of receipt, each subject to certain
limitations;
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100% of the cash proceeds from the incurrence of specified debt
obligations;
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50
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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; and
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100% of the cash proceeds received by us from any initial public
offering or secondary registered offering of equity interests,
until the aggregate amount of such proceeds is equal to
$280 million.
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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 Coffeyville Resources, LLC and its
subsidiaries to incur additional indebtedness, create liens on
assets, make restricted junior payments, enter into agreements
that restrict subsidiary distributions, make investments, loans
or advances, engage in mergers, acquisitions or sales of assets,
dispose of subsidiary interests, enter into sale and leaseback
transactions, engage in certain transactions with affiliates and
stockholders, change the business conducted by the credit
parties, and enter into hedging agreements. The Credit Facility
provides that Coffeyville Resources, LLC may not enter into
commodity agreements if, after giving effect thereto, the
exposure under all such commodity agreements exceeds 75% of
Actual Production (the borrowers estimated future
production of refined products based on the actual production
for the three prior months) or for a term of longer than six
years from December 28, 2006. In addition, the borrower may
not enter into material amendments related to any material
rights under the Cash Flow Swap or the Partnerships
partnership agreement without the prior written approval of the
lenders. These limitations are subject to critical exceptions
and exclusions and are not designed to protect investors in our
common stock.
The Credit Facility also requires the borrower to maintain
certain financial ratios as follows:
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Minimum
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Interest
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Maximum
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Coverage
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Leverage
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Fiscal Quarter Ending
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Ratio
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Ratio
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September 30, 2007
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2.75:1.00
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4.25:1.00
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December 31, 2007
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2.75:1.00
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4.00:1.00
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March 31, 2008
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3.25:1.00
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3.25:1.00
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June 30, 2008
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3.25:1.00
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3.00:1.00
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September 30, 2008
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3.25:1.00
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2.75:1.00
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December 31, 2008
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3.25:1.00
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2.50:1.00
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March 31, 2009 and thereafter
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3.75:1.00
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2.25:1.00
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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
51
scheduled turnaround expenses. As of September 30, 2007, 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 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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2006
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2007
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2006
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2007
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(Unaudited)
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(In millions)
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Consolidated Financial Results
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Net income (loss)
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$
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129.0
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$
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13.4
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$
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170.8
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$
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(40.9
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)
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Plus:
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Depreciation and amortization
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12.8
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18.1
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36.8
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50.3
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Interest expense
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10.7
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18.3
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33.0
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46.0
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Income tax expense (benefit)
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85.3
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47.6
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111.0
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(93.4
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Funded letters of credit expense and interest rate swap not
included in interest expense
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(0.4
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0.7
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0.2
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0.9
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Major scheduled turnaround expense
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4.1
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4.4
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76.8
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Unrealized (gain) or loss on derivatives
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(173.7
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(86.2
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(81.6
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)
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103.8
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Non-cash compensation expense for equity awards
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4.5
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2.3
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11.3
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(Gain) or loss on disposition of fixed assets
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0.8
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0.1
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1.2
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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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)
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Management fees
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0.5
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0.5
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1.6
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1.5
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Adjusted EBITDA
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$
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69.1
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$
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17.1
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$
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279.7
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$
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157.3
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In addition to the financial covenants summarized in the table
above, the Credit Facility restricts the capital expenditures of
Coffeyville Resources, LLC to $375 million in 2007,
$125 million in 2008, $125 million in 2009,
$80 million in 2010, and $50 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 consummates an initial public
offering and 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 million, a breach or default with respect to
material terms under other debt arrangements in an aggregate
amount of at least $20 million which results in the debt
becoming payable or declared due and payable before its stated
maturity, a breach or default under the Cash Flow Swap that
would permit the holder or holders to terminate the Cash Flow
Swap, events of bankruptcy, judgments and attachments exceeding
$20 million, events relating to employee benefit plans
resulting in liability in excess of $20 million, 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
52
portion of the collateral, and any party under the Credit
Facility (other than the agent or lenders under the Credit
Facility) contesting the validity or enforceability of the
Credit Facility.
Under the terms of our Credit Facility, our initial public
offering was deemed a Qualified IPO because the
offering generated at least $250 million of gross proceeds
and we used the proceeds of the offering to repay at least
$275 million of term loans under the Credit Facility. As a
result of our Qualified IPO, the interest margin on LIBOR loans
may in the future decrease from 3.25% to 2.75% (if we have
credit ratings of B2/B) or 2.50% (if we have credit ratings
of B1/B+). Interest on base rate loans will similarly be
adjusted. In addition, as a result of our Qualified IPO,
(1) we will be allowed to borrow an additional
$225 million under the Credit Facility after June 30,
2008 to finance capital enhancement projects if we are in pro
forma compliance with the financial covenants in the Credit
Facility and the rating agencies confirm our ratings,
(2) we will be allowed to pay an additional
$35 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) at
any time after March 31, 2008 we will be allowed to reduce
the Cash Flow Swap to not less than 35,000 barrels a day
for fiscal 2008 and terminate the Cash Flow Swap for any year
commencing with fiscal 2009, so long as our total leverage ratio
is less than or equal to 1.25:1 and we have a corporate family
rating of at least B2 from Moodys and B from S&P.
The Credit Facility is subject to an intercreditor agreement
among the lenders and the Cash Flow Swap provider, which deal
with, among other things, priority of liens, payments and
proceeds of sale of collateral.
At December 31, 2006 and September 30, 2007, funded
long-term debt, including current maturities, totaled
$775.0 million and $771.1 million, respectively, of
tranche D term loans. Other commitments at
December 31, 2006 and September 30, 2007 included a
$150.0 million funded letter of credit facility and a
$150.0 million revolving credit facility. As of
December 31, 2006, the commitment outstanding on the
revolving credit facility was a $6.4 million letter of
credit issued to provide transitional collateral to the lender
that issued $3.2 million in letters of credit in support of
certain environmental obligations and $3.2 million in
letters of credit to secure transportation services for a crude
oil pipeline. As of September 30, 2007, the commitment
outstanding on the revolving credit facility was
$56.9 million, including $20.0 million in borrowings,
$3.3 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 a crude oil pipeline.
Payment
Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our
operations on June 30, 2007, Coffeyville Resources, LLC
entered into several deferral agreements with J. Aron with
respect to the Cash Flow Swap. These deferral agreements
deferred to January 31, 2008 the payment of approximately
$123.7 million (plus accrued interest) which we owed to J.
Aron. J. Aron has agreed to further defer these payments to
August 31, 2008 but we will be required to use 37.5% of our
consolidated excess cash flow for any quarter after
January 31, 2008 to prepay the deferred amounts.
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On June 26, 2007, Coffeyville Resources, LLC and J.
Aron & Company entered into a letter agreement in
which J. Aron deferred to August 7, 2007 a $45 million
payment which we owed to J. Aron under the Cash Flow Swap for
the period ending June 30, 2007. We agreed to pay interest
on the deferred amount at the rate of LIBOR plus 3.25%.
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On July 11, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred to
July 25, 2007 a separate $43.7 million payment which
we owed to J. Aron under the Cash Flow Swap for the period
ending June 30, 2007. J. Aron deferred the
$43.7 million payment on the conditions that (a) each
of GS Capital Partners V Fund, L.P. and Kelso Investment
Associates VII, L.P. agreed to guarantee one half of the payment
and (b) interest accrued on the $43.7 million from
July 9, 2007 to the date of payment at the rate of LIBOR
plus 1.50%.
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On July 26, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred to
September 7, 2007 both the $45 million payment due
August 7, 2007 (and accrued interest) and
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53
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the $43.7 million payment due July 25, 2007 (and
accrued interest). J. Aron deferred these payments on the
conditions that (a) each of GS Capital Partners V Fund,
L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payments and (b) interest accrued
on the amounts from July 26, 2007 to the date of payment at
the rate of LIBOR plus 1.50%.
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On August 23, 2007, Coffeyville Resources, LLC and J. Aron
entered into a letter agreement in which J. Aron deferred
to January 31, 2008 the $45 million payment due
September 7, 2007 (and accrued interest), the
$43.7 million payment due September 7, 2007 (and
accrued interest) and the $35 million payment which we owed
to J. Aron under the Cash Flow Swap to settle hedged volume
through August 15, 2007. J. Aron deferred these payments
(totaling $123.7 million plus accrued interest) on the
conditions that (a) each of GS Capital Partners V
Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payments and (b) interest accrued
on the amounts to the date of payment at the rate of LIBOR plus
1.50%.
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Nitrogen
Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time
to time, seek to raise capital through a public or private
offering of limited partner interests in the Partnership. Any
decision to pursue such a transaction would be made in the
discretion of the managing general partner, not us, and any
proceeds raised in a primary offering would be for the benefit
of the Partnership, not us (although in some cases, depending on
the structure of the transaction, the Partnership might remit
proceeds to us). If the managing general partner elects to
pursue a public or private offering of limited partner interests
in the Partnership, we expect that any such transaction would
require amendments to our Credit Facility, as well as the Cash
Flow Swap, in order to remove the Partnership and its
subsidiaries as obligors under such instruments. Any such
amendments could result in significant changes to our Credit
Facilitys pricing, mandatory repayment provisions,
covenants and other terms and could result in increased interest
costs and require payment by us of additional fees. We have
agreed to use our commercially reasonable efforts to obtain such
amendments if the managing general partner elects to cause the
Partnership to pursue a public or private offering and gives us
at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any
such amendment on terms acceptable to us or at all. If we are
not able to amend our Credit Facility on terms satisfactory to
us, we may need to refinance them with other facilities. We will
not be considered to have used our commercially reasonable
efforts to obtain such amendments if we do not effect the
requested modifications due to (i) payment of fees to the
lenders or the swap counterparty, (ii) the costs of this
type of amendment, (iii) an increase in applicable margins
or spreads or (iv) changes to the terms required by the
lenders including covenants, events of default and repayment and
prepayment provisions; provided that (i), (ii), (iii) and
(iv) in the aggregate are not likely to have a material
adverse effect on us. In order to effect the requested
amendments, we may require that (1) the Partnerships
initial public or private offering generate at least
$140 million in net proceeds to us and (2) the
Partnership raise an amount of cash (from the issuance of equity
or incurrence of indebtedness) equal to $75 million minus
the amount of capital expenditures it will reimburse us for from
the proceeds of its initial public or private offering and to
distribute that cash to us prior to, or concurrently with, the
closing of its initial public or private offering. If the
managing general partner sells interests to third party
investors, we expect that the Partnership may at such time seek
to enter into its own credit facility.
In addition, we may elect to sell our interests in the
Partnership in a secondary public offering (either in connection
with a public offering by the Partnership, but subject to
priority rights in favor of the Partnership, or following
completion of the Partnerships initial public offering, if
any) or in a private placement. Neither the consent of the
managing general partner nor the consent of the Partnership is
required for any sale of our interests in the Partnership, other
than customary blackout periods relating to offerings by the
Partnership. Any proceeds raised would be for our benefit. The
Partnership has granted us registration rights which will
require the Partnership to register our interests with the SEC
at our request from time to time (following any public offering
by the Partnership), subject to various limitations and
requirements.
54
Cash
Flows
The following table sets forth our cash flows for the periods
indicated below:
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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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2006
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2007
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2006
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2007
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Net cash provided by (used in):
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Operating activities
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$
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(22,448
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)
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$
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3,856
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$
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97,861
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$
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161,490
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Investing activities
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(86,775
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)
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(25,642
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)
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(172,950
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)
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(239,695
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)
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Financing activities
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19,442
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26,026
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48,471
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63,604
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Net increase (decrease) in cash and cash equivalents
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$
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(89,781
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)
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$
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4,240
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$
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(26,618
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$
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(14,601
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Cash
Flows Provided by Operating Activities
Net cash flows from operating activities for the nine months
ended September 30, 2007 was $161.5 million. The
positive cash flow from operating activities generated over this
period was primarily driven by favorable changes in other
working capital and trade working capital, partially offset by
unfavorable changes in other assets and liabilities over the
period. For purposes of this cash flow discussion, we define
trade working capital as accounts receivable, inventory and
accounts payable. Other working capital is defined as all other
current assets and liabilities except trade working capital. Net
income for the period was not indicative of the operating
margins for the period. This is the result of the accounting
treatment of our derivatives in general and more specifically,
the Cash Flow Swap. We have determined that the Cash Flow Swap
does not qualify as a hedge for hedge accounting purposes under
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. Therefore, the net loss for the 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) and the NYMEX crack spread that is the basis for the
underlying swaps had increased, the unrealized losses on the
Cash Flow Swap significantly decreased our Net Income over this
period. The impact of these unrealized losses on the Cash Flow
Swap is apparent in the $230.9 million increase in the
payable to swap counterparty. Adding to our operating cash flow
for the nine months ended September 30, 2007 was
$38.1 million source of cash related to changes in trade
working capital. For the nine months ended September 30,
2007, accounts receivable decreased $4.1 million while
inventory increased by $48.4 million resulting in a net use
of cash of $44.3 million. These uses of cash due to changes
in trade working capital were more than offset by an increase in
accounts payable, or a source of cash, of $82.4 million.
The primary uses of cash during the period include a
$96.4 million increase in our insurance receivable related
to the flood and a $2.0 million increase in prepaid
expenses and other current assets. In addition, we also reported
a $36.0 million use of cash related to deferred income
taxes primarily the result of the unrealized loss on the Cash
Flow Swap and a $28.8 million use of cash related to
accrued income taxes primarily related to the tax benefit
recorded for the projected taxable loss through
September 30, 2007.
Net cash flows provided by operating activities for the nine
months ended September 30, 2006 was $97.9 million. The
positive cash flow from operating activities during this period
was primarily the result of strong operating earnings and
favorable changes in other assets and liabilities offset by
unfavorable changes in trade working capital and other working
capital. Net income for the period was not indicative of the
operating margins for the period. This was the result of the
accounting treatment of our derivatives in general and more
specifically, the Cash Flow Swap. We have determined that the
Cash Flow Swap does not qualify as a hedge for hedge accounting
purposes under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. Therefore,
the net income for the nine months ended September 30, 2006
included both the realized losses and the unrealized gains on
the Cash Flow Swap. Since the Cash Flow Swap had a significant
term remaining as of September 30, 2006 (approximately
three years and nine months years) and the NYMEX crack spread
that is the basis for the underlying swaps had decreased during
the period, the unrealized gains on the Cash Flow Swap increased
our Net Income over this period. The impact of these unrealized
gains on the Cash Flow Swap is apparent in the
$88.5 million decrease in the payable to swap counterparty.
Trade working capital resulted in a use of cash of
$37.0 million during the nine
55
months ended September 30, 2006 as the decrease in accounts
receivable of $23.1 million was more than offset by
increases in inventory of $59.8 million and a decrease in
accounts payable of $0.3 million.
Cash
Flows Used in Investing Activities
Net cash used in investing activities for the nine months ended
September 30, 2007 was $239.7 million compared to
$173.0 million for the nine months ended September 30,
2006. The increase in investing activities for the nine months
ended September 30, 2007 as compared to the nine months
ended September 30, 2006 was the result of increased
capital expenditures associated with various capital projects in
our Petroleum business.
Cash
Flows Provided by Financing Activities
Net cash provided by financing activities for the nine months
ended September 30, 2007 was $63.6 million as compared
to net cash provided by financing activities of
$48.5 million for the nine months ended September 30,
2006. 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. For the nine months ended
September 30, 2006, the primary sources of cash were the
result of a $20.0 million issuance of members equity
and $30.0 million of delayed draw term loans both
specifically generated to fund a portion of two discretionary
capital expenditures at our Petroleum operations. During the
nine months ended September 30, 2006, we also paid
$1.7 million of scheduled principal payments.
Working
Capital
Working capital at September 30, 2007, was
$(27.0) million, consisting of $576.3 million in
current assets and $603.3 million in current liabilities.
Working capital at December 31, 2006, was
$112.3 million, consisting of $342.5 million in
current assets and $230.2 million in current liabilities.
In addition, we had available borrowing capacity under our 2007
Revolving Credit Facility of $168.1 million at
September 30, 2007.
Letters
of Credit
Our revolving credit facility provides for the issuance of
letters of credit. At September 30, 2007, there were
$36.9 million of irrevocable letters of credit outstanding,
$3.3 million in support of certain environmental
obligators, $30.6 million to secure transportation services
for crude oil and $3.0 million in support for surety bonds
in place to support state and federal excise tax for refined
fuels.
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements as of
September 30, 2007.
Critical
Accounting Policies
We prepare our consolidated financial statements in accordance
with GAAP. In order to apply these principles, management must
make judgments, assumptions and estimates based on the best
available information at the time. Actual results may differ
based on the accuracy of the information utilized and subsequent
events. Our critical accounting policies, which are described
below, could materially affect the amounts recorded in our
financial statements.
Derivative
Instruments and Fair Value of Financial Instruments
We use futures contracts, options, and forward contracts
primarily to reduce exposure to changes in crude oil prices,
finished goods product prices and interest rates to provide
economic hedges of inventory positions and anticipated interest
payments on long term-debt. Although management considers these
derivatives economic hedges, the Cash Flow Swap and our other
derivative instruments do not qualify as hedges for hedge
accounting
56
purposes under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, and
accordingly are recorded at fair value in the balance sheet.
Changes in the fair value of these derivative instruments are
recorded into earnings as a component of other income (expense)
in the period of change. The estimated fair values of forward
and swap contracts are based on quoted market prices and
assumptions for the estimated forward yield curves of related
commodities in periods when quoted market prices are
unavailable. The Company recorded net gains (losses) from
derivative instruments of $44.7 million and
$(251.9) million in gain (loss) on derivatives for the nine
months ended September 30, 2006 and 2007, respectively. Net
gains from derivative instruments of $171.2 million and
$40.5 million were recorded for the three months ended
September 30, 2006 and 2007, respectively.
As of September 30, 2007, a $1.00 change in quoted prices
for the crack spreads utilized in the Cash Flow Swap would
result in a $48.5 million change to the fair value of
derivative commodity position and the same change to net income.
Environmental
Expenditures
Liabilities related to future remediation of contaminated
properties are recognized when the related costs are considered
probable and can be reasonably estimated. Estimates of these
costs are based upon currently available facts, existing
technology, site-specific costs, and currently enacted laws of
regulations. In reporting environmental liabilities, no offset
is made for potential recoveries. All liabilities are monitored
and adjusted as new facts or changes in law or technology occur.
Environmental expenditures are capitalized when such costs
provide future economic benefits. Changes in laws, regulations
or assumptions used in estimating these costs could have a
material impact to our financial statements. The amount recorded
for environmental obligations (exclusive of estimated
obligations associated with the crude oil discharge) at
September 30, 2007 totaled $7.2 million, including
$1.6 million included in current liabilities. Additionally,
at September 30, 2007, $17.4 million was included in
current liabilities for the estimated future remediation
obligations arising from the crude oil discharge. This amount
also included estimated obligations to settle third party
property damage claims resulting from the crude oil discharge.
Share-Based
Compensation
We estimated fair value of units for all applicable periods as
described below.
For the year ended December 31, 2006 and the nine months
ended September 30, 2006 and 2007, we account for
share-based compensation in accordance with
SFAS No. 123(R), Share-Based Payments.
SFAS 123(R) requires that compensation costs relating to
share-based payment transactions be recognized in a
companys financial statements. SFAS 123(R) applies to
transactions in which an entity exchanges its equity instruments
for goods or services and also may apply to liabilities an
entity incurs for goods or services that are based on the fair
value of those equity instruments.
In accordance with SFAS 123(R), we apply a fair-value-based
measurement method in accounting for share-based override units
and phantom points. Override units are equity classified awards
measured using the grant date fair value with compensation
expense recognized over the respective vesting period. Phantom
points are liability classified awards marked to market based on
their fair value at the end of each reporting period with
compensation expense recognized over the respective vesting
period.
At June 24, 2005 an independent third party appraisal for
the refinery and the nitrogen fertilizer plant were obtained.
Additionally, an independent appraisal process occurred at that
time, to value the management common units that were subject to
redemption and our override value units, override operating
units and phantom points. The Monte Carlo method of valuation
was utilized to value the override operating units, override
value units and phantom points that were issued on June 24,
2005.
In addition, an independent appraisal process occurs each
reporting period in order to revalue the management common units
and phantom points. The significant assumptions that are used
each reporting period to value the phantom and performance
service points are: (1) estimated forfeiture rate;
(2) explicit service period or derived service period as
applicable, (3) grant-date fair value
controlling basis; (4) marketability and minority interest
discounts and (5) volatility.
57
For the independent valuations that occurred as of
December 31, 2005, June 30, 2006 and
September 30, 2006, a Binomial Option Pricing Model was
utilized to value the phantom points. Probability-weighted
values that were determined in this independent valuation
process were discounted to determine the present value of the
units. Prospective financial information is utilized in the
valuation process. A discounted cash flow method, a variation of
the income approach, and a guideline company method, which is a
variation of a market approach is utilized to value the
management common units.
A combination of a binomial model and a probability-weighted
expected return method which utilizes the companys cash
flow projections was utilized to value the additional override
operating units and override value units that were issued on
December 28, 2006. Additionally, this combination of a
binomial model and probability-weighted expected return method
was utilized to value the phantom points as of December 31,
2006, March 31, 2007, and June 30, 2007. Management
believed that this method was preferable for the valuation of
the override units and phantom points as it allowed a better
integration of the cash flows with other inputs including the
timing of potential exit events that impact the estimated fair
value of the override units and phantom points.
At September 30, 2007, the management common units that
were subject to redemption and the phantom points were revalued
through an independent appraisal process based upon a
calculation utilizing the initial public offering share price.
Assuming the price of the Companys common stock increases
$1.00, additional compensation expense of approximately
$2.2 million would be recognized over the vesting period
for phantom points.
Income
Taxes
Income tax expense is estimated based on the projected effective
tax rate based upon future tax return filings. The amounts
anticipated to be reported in those filings may change between
the time the financial statements are prepared and the time the
tax returns are filed. Further, because tax filings are subject
to review by taxing authorities, there is also the risk that a
position on a tax return may be challenged by a taxing
authority. If the taxing authority is successful in asserting a
position different than that taken by us, differences in a tax
expense or between current and deferred tax items may arise in
future periods. Any of these differences which could have a
material impact on our financial statements would be reflected
in the financial statements when management considers them
probable of occurring and the amount reasonably estimable.
Valuation allowances reduce deferred tax assets to an amount
that will more likely than not be realized. Managements
estimates of the realization of deferred tax assets are based on
the information available at the time the financial statements
are prepared and may include estimates of future income and
other assumptions that are inherently uncertain. No valuation
allowance is currently recorded, as we expect to realize our
deferred tax assets.
Consolidation
of Variable Interest Entities
In accordance with FASB Interpretation No. 46R,
Consolidation of Variable Interest Entities, or
FIN No. 46R, management has reviewed the terms
associated with our current interests in the Partnership based
upon the partnership agreement. Management has determined that
the Partnership is treated as a variable interest entity
(VIE) and as such has evaluated the criteria under
FIN 46R to determine that we are the primary beneficiary of
the Partnership. FIN 46R requires the primary beneficiary
of a variable interest entitys activities to consolidate
the VIE. FIN 46R defines a variable interest entity as an
entity in which the equity investors do not have substantive
voting rights and where there is not sufficient equity at risk
for the entity to finance its activities without additional
subordinated financial support. As the primary beneficiary, we
absorb the majority of the expected losses
and/or
receive a majority of the expected residual returns of the
VIEs activities.
We will need to reassess our investment in the Partnership from
time to time to determine whether we are the primary
beneficiary. If in the future we conclude that we are no longer
the primary beneficiary, we will be required to deconsolidate
the activities of the Partnership on a going forward basis. The
interest would then be recorded using the equity method and the
Partnership gross revenues, expenses, net income, assets and
liabilities as such would not be included in our consolidated
financial statements.
58
Recent
Accounting Developments
In February 2007, the Financial Accounting Standards Board
(FASB) issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of
SFAS No. 115
(SFAS No. 159), which provides
companies with an option to report select financial assets and
liabilities at fair value. This statement also establishes
presentation and disclosure requirements designed to facilitate
comparisons between companies that choose different measurement
attributes for similar types of assets and liabilities.
SFAS No. 159 is effective as of the beginning of the
2008 fiscal year. We are in the process of evaluating the impact
that adoption of SFAS No. 159 will have on our results
of operations and financial condition.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
(SFAS No. 157). This statement defines
fair value, establishes a framework for measuring fair value and
expands disclosure of fair value measurements.
SFAS No. 157 applies under other accounting
pronouncements that require or permit fair value measurements
and accordingly, does not require any new fair value
measurements. SFAS No. 157 is effective as of the
beginning of the 2008 fiscal year. We are in the process of
evaluating the impact that adoption of SFAS No. 157
will have on our results of operations and financial condition.
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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. None of our market risk
sensitive instruments are held for trading.
Commodity
Price Risk
Our petroleum business, as a manufacturer of refined petroleum
products, and the nitrogen fertilizer business, as a
manufacturer of nitrogen fertilizer products, all of which are
commodities, have exposure to market pricing for products sold
in the future. In order to realize value from our processing
capacity, a positive spread between the cost of raw materials
and the value of finished products much be achieved (i.e., gross
margin or crack spread). The physical commodities that comprise
our raw materials and finished goods are typically bought and
sold at a spot or index price that can be highly variable.
We use a crude oil purchasing intermediary which allows us to
take title and price of our crude oil at the refinery, as
opposed to the crude origination point, reducing our risk
associated with volatile commodity prices by shortening the
commodity conversion cycle time. The commodity conversion cycle
time refers to the time elapsed between raw material acquisition
and the sale of finished goods. In addition, we seek to reduce
the variability of commodity price exposure by engaging in
hedging strategies and transactions that will serve to protect
gross margins as forecasted in the annual operating plan.
Accordingly, we use financial derivatives to economically hedge
future cash flows (i.e., gross margin or crack spreads) and
product inventories. With regard to our hedging activities, we
may enter into, or have entered into, derivative instruments
which serve to:
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Lock in or fix a percentage of the anticipated or planned gross
margin in future periods when the derivative market offers
commodity spreads that generate positive cash flows; and
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Hedge the value of inventories in excess of minimum required
inventories.
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Further, we intend to engage only in risk mitigating activities
directly related to our business.
Basis Risk. The effectiveness of our
derivative strategies is dependent upon the correlation of the
price index utilized for the hedging activity and the cash or
spot price of the physical commodity for which price risk is
being mitigated. Basis risk is a term we use to define that
relationship. Basis risk can exist due to several factors
including time or location differences between the derivative
instrument and the underlying physical commodity. Our selection
of the appropriate index to utilize in a hedging strategy is a
prime consideration in our basis risk exposure.
Examples of our basis risk exposure are as follows:
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Time Basis In entering over-the counter swap
agreements, the settlement price of the swap is typically the
average price of the underlying commodity for a designated
calendar period. This settlement price is based on the
assumption that the underlying physical commodity will price
ratably over the swap period. If the
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59
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commodity does not move ratably over the periods than weighted
average physical prices will be weighted differently than the
swap price as the result of timing.
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Location Basis In hedging NYMEX crack spreads, we
experience location basis as the settlement of NYMEX refined
products (related more to New York Harbor cash markets) which
may be different than the prices of refined products in our
Group 3 pricing area.
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Price and Basis Risk Management
Activities. Our most prevalent risk management
activity is to sell forward the crack spread when opportunities
exist to lock in a margin sufficient to meet our cash
obligations or our operating plan. Selling forward derivative
contracts for which the underlying commodity is the crack spread
enables us to lock in a margin on the spread between the price
of crude oil and price of refined products. The commodity
derivative contracts are either exchange-traded contracts in the
form of futures contracts or over-the-counter contracts in the
form of commodity price swaps.
In the event our inventories exceed our target base level of
inventories, we may enter into commodity derivative contracts to
manage our price exposure to our inventory positions that are in
excess of our base level. Excess inventories are typically the
result of plant operations such as a turnaround or other plant
maintenance. The commodity derivative contracts are either
exchange-traded contracts in the form of futures contracts or
over-the-counter contracts in the form of commodity price swaps.
To reduce the basis risk between the price of products for Group
3 and that of the NYMEX associated with selling forward
derivative contracts for NYMEX crack spreads, we may enter into
basis swap positions to lock the price difference. If the
difference between the price of products on the NYMEX and Group
3 (or some other price benchmark as we may deem appropriate) is
different than the value contracted in the swap, then we will
receive from or owe to the counterparty the difference on each
unit of product contracted in the swap, thereby completing the
locking of our margin. An example of our use of a basis swap is
in the winter heating oil season. The risk associated with not
hedging the basis when using NYMEX forward contracts to fix
future margins is if the crack spread increases based on prices
traded on NYMEX while Group 3 pricing remains flat or decreases
then we would be in a position to lose money on the derivative
position while not earning an offsetting additional margin on
the physical position based on the Group 3 pricing.
As of September 30, 2007, a $1.00 change in quoted futures
price for the crack spreads described in the first bullet point
would result in a $48.5 million change to the fair value of
the derivative commodity position and the same change in net
income.
Interest
Rate Risk
As of September 30, 2007, all of our $821.1 million of
outstanding term debt was at floating rates. An increase of 1.0%
in the LIBOR rate would result in an increase in our interest
expense of approximately $8.3 million per year.
As of September 30, 2007, all of our $20.0 million of
outstanding revolving debt was at floating rates based on prime.
If this amount remained outstanding for an entire year, an
increase of 1.0% in the prime rate would result in an increase
in our interest expense of approximately $0.2 million per
year.
In an effort to mitigate the interest rate risk highlighted
above and as required under our then-existing first and second
lien credit agreements, we entered into several interest rate
swap agreements in 2005. These swap agreements were entered into
with counterparties that we believe to be creditworthy. Under
the swap agreements, we pay fixed rates and receive floating
rates based on the three-month LIBOR rates, with payments
calculated on the notional amounts set for in the table below.
The interest rate swaps are settled quarterly and marked to
market at each reporting date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
|
|
|
Termination
|
|
|
Fixed
|
|
Notional Amount
|
|
Date
|
|
|
Date
|
|
|
Rate
|
|
|
$325.0 million
|
|
|
6/29/07
|
|
|
|
3/30/08
|
|
|
|
4.195
|
%
|
$250.0 million
|
|
|
3/31/08
|
|
|
|
3/30/09
|
|
|
|
4.195
|
%
|
$180.0 million
|
|
|
3/31/09
|
|
|
|
3/30/10
|
|
|
|
4.195
|
%
|
$110.0 million
|
|
|
3/31/10
|
|
|
|
6/29/10
|
|
|
|
4.195
|
%
|
60
We have determined that these interest rate swaps do not qualify
as hedges for hedge accounting purposes. Therefore, changes in
the fair value of these interest rate swaps are included in
income in the period of change. Net realized and unrealized
gains or losses are reflected in the gain (loss) for derivative
activities at the end of each period. For the year ended
December 31, 2006, we had $3.7 million of realized and
unrealized gains on these interest rate swaps and for the nine
months ended September 30, 2007, we had $1.4 million
of realized and unrealized losses.
|
|
Item 4.
|
Controls
and Procedures
|
|
|
(a)
|
Evaluation
of disclosure controls and procedures.
|
Our management has evaluated, with the participation of our
principal executive and principal financial officer, the
effectiveness of our disclosure controls and procedures (as
defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act)) as of the end of the period covered by this report,
and has concluded that our disclosure controls and procedures
are effective to provide reasonable assurance that information
required to be disclosed by us in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized
and reported, within the time periods specified in the
Securities and Exchange Commissions rules and forms.
|
|
(c)
|
Changes
in internal control over financial reporting.
|
There has been no change in our internal control over financial
reporting (as described in
Rule 13a-15(f)
under the Exchange Act) that occurred during CVRs last
fiscal quarter that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
Part II.
Other Information
|
|
Item 1.
|
Legal
Proceedings
|
As a result of the crude oil discharge on or about July 1,
2007, two putative class action lawsuits (one federal and one
state) were filed against us
and/or our
subsidiaries in July 2007.
The federal suit, Danny Dunham vs. Coffeyville Resources,
LLC, et al., was filed in the United States District Court
for the District of Kansas at Wichita (Case
No. 07-CV-01186-JTM-DWB).
Plaintiffs complaint alleged that the crude oil discharge
resulted from our negligent operation of the refinery and that
class members suffered unspecified damages, including damages to
their personal and real property, diminished property value,
lost full use and enjoyment of their property, lost or
diminished business income and comprehensive remediation costs.
The federal suit sought recovery under the federal Oil Pollution
Act, Kansas statutory law imposing a duty of compensation on a
party that releases any material detrimental to the soil or
waters of Kansas, and the Kansas common law of negligence,
trespass and nuisance. This suit was dismissed on
November 6, 2007 for lack of subject matter jurisdiction.
Under the Class Action Fairness Act of 2005, a court must
decline jurisdiction if two-thirds or more of the members of all
proposed plaintiff classes in the aggregate, and the primary
defendants, are citizens of the state in which the action was
originally filed. The suit was dismissed for lack of subject
matter jurisdiction because the court determined that two-thirds
or more of the members of all proposed plaintiff classes in the
aggregate, and the primary defendants, were citizens of Kansas.
It is possible that the plaintiffs in the federal suit may
appeal the dismissal in federal court or take other actions to
continue their claims, in which case, we plan on vigorously
defending against such claims. Due to the uncertainty of such
claims, we are unable to estimate a range of possible loss at
this time. Presently, we do not expect that the resolution of
these claims will have a significant adverse effect on our
business and results of operations.
61
The state suit, Western Plains Alliance, LLC and Western Plains
Operations, LLC v. Coffeyville Resources
Refining & Marketing, LLC, was filed in the District
Court of Montgomery County, Kansas (case number 07CV99I). This
suit seeks class certification under applicable law. The
proposed class consists of all persons and entities who own or
have owned real property within the contaminated
area, and all businesses
and/or other
entities located within the contaminated area. To
date no class has yet been certified, and any class, if
certified, may be broader, narrower, or different than the class
currently proposed. The Court conducted an evidentiary hearing
on the issue of class certification on October 24 and 25, 2007
and a decision on whether a class will be certified is expected
in the near future.
The state suit alleges that the class has suffered damages,
including damages to real and personal property, decreases in
property values, decreases in business revenues, loss of the
right to the full and exclusive use of real property, increased
costs for maintenance and upkeep, and costs for monitoring,
detection, management and removal of the crude oil. The suit
asserts claims against us related to negligence, nuisance and
trespass. The complaint also alleges that we have a duty under
Kansas statutory law to compensate owners of property affected
by the release or discharge of contamination. The suit seeks
unspecified damages as well as injunctive relief requiring us to
take such steps as are reasonably necessary to prevent the
further migration of the crude oil and for the remediation
and/or
removal of the crude oil. We have filed an answer in the state
suit denying any liability for negligence, nuisance and
trespass, while acknowledging that plaintiffs property
damages and losses resulting from the oil release (but not from
the flood) are properly compensable pursuant to Kansas state law
if plaintiffs did not contribute to such contamination.
We intend to defend against the state suit vigorously. Due to
the uncertainty of this suit, we are unable to estimate a range
of possible loss at this time. Presently, we do not expect that
the resolution of the state suit or both the state and federal
suits will have a significant adverse effect on our business and
results of operations.
|
|
(2)
|
EPA
Administrative Order on Consent
|
On July 10, 2007, we entered into an administrative order
on consent (the Consent Order) with the United
States Environmental Protection Agency (the EPA). As
set forth in the Consent Order, the EPA concluded that the
discharge of oil from our refinery caused and may continue to
cause an imminent and substantial threat to the public health
and welfare. Pursuant to the Consent Order, we agreed to perform
specified remedial actions to respond to the discharge of crude
oil from our refinery.
The Company has included Risk Factors as
Exhibit 99.1 to this
Form 10-Q.
|
|
Item 2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
Use of
Proceeds
On October 22, 2007 the SEC declared effective our
registration statements on
Form S-1
(Registration Nos.
333-137588)
related to our sale of 23,000,000 shares of our common
stock. On October 26, 2007, we completed an initial public
offering of 23,000,000 shares at a price of $19.00 per
share for an aggregate offering price of approximately
$437.0 million. Of the aggregate gross proceeds,
approximately $11.4 million was used to pay offering
expenses related to the initial public offering, and
$28.5 million was used to pay underwriting discounts and
commissions. None of the expenses incurred and paid by us in
this offering were direct or indirect payment (i) to our
directors, officers, general partners or their associates,
(ii) to persons owning 10% or more of any class of our
equity securities, or (iii) to our affiliates. Net proceeds
of the offering after payment of expenses and underwriting
discounts and commission were approximately $397.1 million.
The offering was made through an underwriting syndicate let by
Goldman, Sachs & Col, Deutsch Bank Securities, Credit
Suisse, and Simmons & Company International as joint
book-running managers.
62
As of November 30, 2007, we used the net proceeds from the
offering as follows:
|
|
|
|
|
Payment of term debt of $280.0 million and related interest
of approximately $5.7 million;
|
|
|
|
Repayment of $25 million under the unsecured credit
facility and repayment of $25.0 million under the secured
facility including related interest of approximately
$.2 million;
|
|
|
|
Repayment of revolver borrowings of $50.0 million;
|
|
|
|
Payment of a $5.0 termination fee to each of Goldman,
Sachs & Co. and Kelso & Company, L.P. in
connection with the termination of the management agreements in
conjunction with the initial public offering; and
|
|
|
|
$1.2 million was used for general corporate purposes.
|
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
On October 16, 2007, our stockholders, consisting of
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC, consented to the following actions by written consent:
|
|
|
|
|
The election of the current members of our board of directors,
effective as of October 16, 2007;
|
|
|
|
The adoption of our Amended and Restated Certificate of
Incorporation, dated October 16, 2007, and our Amended and
Restated By-Laws;
|
|
|
|
The adoption of the CVR Energy, Inc. 2007 Long Term Incentive
Plan;
|
|
|
|
The grant of options to purchase 5,150 shares of our common
stock to each of Messrs. Regis B. Lippert and Mark Tomkins;
|
|
|
|
The grant of 5,000 shares of restricted stock to
Mr. Lippert and the grant of 12,500 shares of
restricted stock to Mr. Tomkins; and
|
|
|
|
The grant of 50 shares of our common stock to 542 of our
employees.
|
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.1
|
|
Amended and Restated Certificate of Incorporation of CVR Energy,
Inc., dated October 16, 2007.
|
|
10
|
.2
|
|
Amended and Restated By-Laws of CVR Energy, Inc.
|
|
10
|
.3
|
|
Amended and Restated Recapitalization Agreement, dated as of
October 16, 2007, by and among Coffeyville Acquisition LLC,
Coffeyville Refining & Marketing Holdings, Inc.,
Coffeyville Refining & Marketing, Inc., Coffeyville
Nitrogen Fertilizers, Inc. and CVR Energy, Inc.
|
|
10
|
.4
|
|
First Amended and Restated Limited Partnership Agreement of CVR
Partners, LP, dated as of October 24, 2007, by and among
CVR GP, LLC, CVR Special GP, LLC and Coffeyville Resources, LLC.
|
|
10
|
.5
|
|
Coke Supply Agreement, dated as of October 25, 2007, by and
between Coffeyville Resources Refining & Marketing,
LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
|
|
10
|
.6
|
|
Cross Easement Agreement, dated as of October 25, 2007, by
and between Coffeyville Resources Refining &
Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers,
LLC.
|
|
10
|
.7
|
|
Environmental Agreement, dated as of October 25, 2007, by
and between Coffeyville Resources Refining &
Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers,
LLC.
|
|
10
|
.8
|
|
Feedstock and Shared Services Agreement, dated as of
October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources
Nitrogen Fertilizers, LLC.
|
|
10
|
.9
|
|
Raw Water and Facilities Sharing Agreement, dated as of
October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources
Nitrogen Fertilizers, LLC.
|
|
10
|
.10
|
|
Services Agreement, dated as of October 25, 2007, by and
among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and
CVR Energy, Inc.
|
63
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.11
|
|
Omnibus Agreement, dated as of October 24, 2007 by and
among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR
Partners, LP.
|
|
10
|
.12
|
|
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan
II).
|
|
10
|
.13
|
|
CVR Energy, Inc. 2007 Long Term Incentive Plan.
|
|
10
|
.14
|
|
Third Amended and Restated Limited Liability Company Agreement
of Coffeyville Acquisition LLC, dated as of October 16,
2007.
|
|
10
|
.15
|
|
Amendment No. 1 to the Third Amended and Restated Limited
Liability Company Agreement of Coffeyville Acquisition LLC,
dated as of October 24, 2007.
|
|
10
|
.16
|
|
First Amended and Restated Limited Liability Company Agreement
of Coffeyville Acquisition II LLC, dated as of
October 16, 2007.
|
|
10
|
.17
|
|
Amendment No. 1 to the First Amended and Restated Limited
Liability Company Agreement of Coffeyville Acquisition II
LLC, dated as of October 24, 2007.
|
|
10
|
.18
|
|
Limited Liability Company Agreement of Coffeyville
Acquisition III LLC, dated as of October 16, 2007.
|
|
10
|
.19
|
|
Redemption Agreement, dated as of October 16, 2007, by
and among Coffeyville Acquisition LLC and the Redeemed Parties
signatory thereto.
|
|
10
|
.20
|
|
Stockholders Agreement of CVR Energy, Inc., dated as of
October 16, 2007, by and among CVR Energy, Inc.,
Coffeyville Acquisition LLC and Coffeyville Acquisition II
LLC.
|
|
10
|
.21
|
|
Registration Rights Agreement, dated as of October 16,
2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC
and Coffeyville Acquisition II LLC.
|
|
10
|
.22
|
|
Subscription Agreement, dated as of October 16, 2007, by
and between CVR Energy, Inc. and John J. Lipinski.
|
|
10
|
.23
|
|
Letter Agreement, dated as of October 24, 2007, by and
among Coffeyville Acquisition LLC, Goldman, Sachs &
Co. and Kelso & Company, L.P.
|
|
10
|
.24
|
|
Registration Rights Agreement, dated as of October 24,
2007, by and among CVR Partners, LP, CVR Special GP, LLC and
Coffeyville Resources, LLC.
|
|
10
|
.25
|
|
CVR Partners, LP Profit Bonus Plan.
|
|
10
|
.26
|
|
Contribution, Conveyance and Assumption Agreement, dated as of
October 24, 2007, by and among Coffeyville Resources, LLC,
CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP.
|
|
10
|
.27
|
|
Management Registration Rights Agreement, dated as of
October 16, 2007, by and between CVR Energy, Inc.
and John J. Lipinski.
|
|
10
|
.28
|
|
Amendment Number 2 to Employment Agreement, dated as of
October 16, 2007, by and between Coffeyville Resources, LLC
and John J. Lipinski, Stanley A. Riemann, James T. Rens, Robert
W. Haugen, and Wyatt E. Jernigan, respectively.
|
|
31
|
.1
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive
Officer.
|
|
31
|
.2
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial
Officer.
|
|
32
|
.1
|
|
Section 1350 Certification of Chief Executive Officer.
|
|
99
|
.1
|
|
Risk Factors.
|
64
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
sixth day of December 2007.
CVR Energy, Inc.
Chief Executive Officer
(Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
65