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
March 31, 2009
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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
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77479
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Sugar Land, Texas
(Address of principal
executive offices)
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(Zip Code)
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Registrants telephone number, including area code:
(281) 207-3200
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes
þ
No
o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 or
Regulation S-T
(§232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
o
No
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer
o
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Accelerated
filer
þ
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Non-accelerated
filer
o
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Smaller
reporting
company
o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined by
Rule 12b-2
of the Exchange
Act). Yes
o
No
þ
There were 86,244,245 shares of the registrants
common stock outstanding at May 5, 2009.
CVR
ENERGY, INC. AND SUBSIDIARIES
INDEX TO
QUARTERLY REPORT ON
FORM 10-Q
For The
Quarter Ended March 31, 2009
PART I.
FINANCIAL INFORMATION
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ITEM 1.
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FINANCIAL
STATEMENTS
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CVR
ENERGY, INC. AND SUBSIDIARIES
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March 31,
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December 31,
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2009
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2008
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(unaudited)
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(in thousands, except
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share data)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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28,427
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$
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8,923
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Restricted cash
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34,560
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Accounts receivable, net of allowance for doubtful accounts of
$4,313 and $4,128, respectively
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65,609
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33,316
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Inventories
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173,056
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148,424
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Prepaid expenses and other current assets
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22,321
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37,583
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Receivable from swap counterparty
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18,355
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32,630
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Insurance receivable
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11,756
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Income tax receivable
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16,074
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40,854
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Deferred income taxes
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31,000
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25,365
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Total current assets
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354,842
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373,411
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Property, plant, and equipment, net of accumulated depreciation
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1,170,328
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1,178,965
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Intangible assets, net
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402
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410
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Goodwill
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40,969
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40,969
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Deferred financing costs, net
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3,348
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3,883
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Receivable from swap counterparty
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2,433
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5,632
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Insurance receivable
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1,000
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1,000
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Other long-term assets
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2,481
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6,213
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Total assets
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$
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1,575,803
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$
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1,610,483
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LIABILITIES AND EQUITY
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Current liabilities:
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Current portion of long-term debt
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$
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4,813
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$
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4,825
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Note payable and capital lease obligation
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7,821
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11,543
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Payable to swap counterparty
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15,714
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62,375
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Accounts payable
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76,713
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105,861
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Personnel accruals
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13,776
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10,350
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Accrued taxes other than income taxes
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20,498
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13,841
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Deferred revenue
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8,418
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5,748
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Other current liabilities
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32,162
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30,366
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Total current liabilities
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179,915
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244,909
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Long-term liabilities:
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Long-term debt, net of current portion
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478,304
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479,503
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Accrued environmental liabilities, net of current portion
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3,940
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4,240
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Deferred income taxes
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289,695
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289,150
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Other long-term liabilities
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1,263
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2,614
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Total long-term liabilities
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773,202
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775,507
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Commitments and contingencies
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Equity:
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CVR stockholders equity:
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Common Stock $0.01 par value per share,
350,000,000 shares authorized; 86,243,745 shares
issued and outstanding
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862
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862
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Additional
paid-in-capital
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443,128
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441,170
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Retained earnings
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168,096
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137,435
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Total CVR stockholders equity
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612,086
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579,467
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Noncontrolling interest in subsidiary
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10,600
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10,600
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Total equity
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622,686
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590,067
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Total liabilities and equity
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$
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1,575,803
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$
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1,610,483
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See accompanying notes to the condensed consolidated financial
statements.
2
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Three Months Ended
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March 31,
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2009
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2008
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(unaudited)
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(in thousands, except share data)
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Net sales
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$
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609,395
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$
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1,223,003
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Operating costs and expenses:
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Cost of product sold (exclusive of depreciation and amortization)
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421,605
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1,036,194
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Direct operating expenses (exclusive of depreciation and
amortization)
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56,234
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60,556
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Selling, general and administrative expenses (exclusive of
depreciation and amortization)
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19,506
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13,497
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Net costs associated with flood
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181
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5,763
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Depreciation and amortization
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20,909
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19,635
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Total operating costs and expenses
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518,435
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1,135,645
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Operating income
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90,960
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87,358
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Other income (expense):
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Interest expense and other financing costs
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(11,470
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(11,298
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Interest income
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14
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702
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Gain (loss) on derivatives, net
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(36,861
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(47,871
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Other income, net
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25
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179
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Total other income (expense)
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(48,292
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(58,288
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Income before income tax expense
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42,668
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29,070
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Income tax expense
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12,007
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6,849
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Net income
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$
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30,661
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$
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22,221
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Basic earnings per share
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$
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0.36
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$
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0.26
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Diluted earnings per share
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$
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0.36
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$
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0.26
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Weighted average common shares outstanding:
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Basic
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86,243,745
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86,141,291
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Diluted
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86,322,411
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86,158,791
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See accompanying notes to the condensed consolidated financial
statements.
3
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Three Months Ended
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March 31,
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2009
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2008
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(unaudited)
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(in thousands)
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Cash flows from operating activities:
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Net income
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$
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30,661
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$
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22,221
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Adjustments to reconcile net income to net cash provided by
operating activities:
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Depreciation and amortization
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20,909
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19,635
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Provision for doubtful accounts
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185
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206
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Amortization of deferred financing costs
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535
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495
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Loss on disposition of fixed assets
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8
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16
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Share-based compensation
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3,854
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(383
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)
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Changes in assets and liabilities:
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Restricted cash
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34,560
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Accounts receivable
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(32,478
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)
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(30,693
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Inventories
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(24,632
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(31,642
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)
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Prepaid expenses and other current assets
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11,580
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75
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Insurance receivable
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(1,915
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)
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Insurance proceeds from flood
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11,756
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1,500
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Other long-term assets
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3,622
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(3,159
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)
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Accounts payable
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(25,392
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)
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(5,166
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)
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Accrued income taxes
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24,780
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5,201
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Deferred revenue
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2,670
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16,623
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Other current liabilities
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9,983
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5,315
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Payable to swap counterparty
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(29,187
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)
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20,750
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Accrued environmental liabilities
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(300
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)
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80
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Other long-term liabilities
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(1,351
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)
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3,325
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Deferred income taxes
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(5,090
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)
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1,710
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Net cash provided by operating activities
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36,673
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24,194
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Cash flows from investing activities:
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Capital expenditures
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(15,918
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)
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(26,156
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)
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Net cash used in investing activities
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(15,918
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)
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(26,156
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Cash flows from financing activities:
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Revolving debt payments
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(72,200
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)
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(123,000
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Revolving debt borrowings
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72,200
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123,000
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Principal payments on long-term debt
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(1,211
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)
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(1,223
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)
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Payment of capital lease obligation
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(40
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)
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Deferred costs of CVR Partners, LP initial public offering
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(2,145
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)
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Net cash used in financing activities
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(1,251
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)
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(3,368
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)
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Net increase (decrease) in cash and cash equivalents
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19,504
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(5,330
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)
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Cash and cash equivalents, beginning of period
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8,923
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30,509
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Cash and cash equivalents, end of period
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$
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28,427
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$
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25,179
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Supplemental disclosures:
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Cash paid for income taxes, net of refunds (received)
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$
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(7,683
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)
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$
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(63
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)
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Cash paid for interest, net of capitalized interest of $413 and
$1,118 in 2009 and 2008, respectively
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9,102
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10,723
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Non-cash investing and financing activities:
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Accrual of construction in progress additions
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(3,756
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)
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(6,237
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)
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See accompanying notes to the condensed consolidated financial
statements.
4
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(1)
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Organization
and History of the Company and Basis of Presentation
|
Organization
The Company or CVR may be used to refer
to CVR Energy, Inc. and, unless the context otherwise requires,
its subsidiaries. Any references to the Company as
of a date 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.
The Company, through its wholly-owned subsidiaries, acts as an
independent petroleum refiner and marketer in the
mid-continental United States. In addition, the Company, through
its majority-owned subsidiaries, acts as an independent producer
and marketer of upgraded nitrogen fertilizer products in North
America. The Companys operations include two business
segments: the petroleum segment and the nitrogen fertilizer
segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary,
incorporated in Delaware in September 2006, in order to effect
an initial public offering. The initial public offering of CVR
was consummated on October 26, 2007. In conjunction with
the initial public offering, a restructuring occurred in which
CVR became a direct or indirect owner of all of the subsidiaries
of CALLC. Additionally, in connection with the initial public
offering, CALLC was split into two entities: CALLC and
Coffeyville Acquisition II LLC (CALLC II).
CVR is a controlled company under the rules and regulations of
the New York Stock Exchange where its shares are traded under
the symbol CVI. As of March 31, 2009,
approximately 73% of its outstanding shares were beneficially
owned by GS Capital Partners V, L.P. and related entities
(GS or Goldman Sachs Funds) and Kelso
Investment Associates VII, L.P. and related entities
(Kelso or Kelso Funds).
Nitrogen
Fertilizer Limited Partnership
In conjunction with the consummation of CVRs initial
public offering in 2007, CVR transferred Coffeyville Resources
Nitrogen Fertilizer, LLC (CRNF), its nitrogen
fertilizer business, to a newly created limited partnership, CVR
Partners, LP (the Partnership), in exchange for a
managing general partner interest (managing GP
interest), a special general partner interest
(special GP interest, represented by special GP
units) and a de minimis limited partner interest (LP
interest, represented by special LP units). This transfer
was not considered a business combination as it was a transfer
of assets among entities under common control and, accordingly,
balances were transferred at their historical cost. CVR
concurrently sold the managing GP interest to Coffeyville
Acquisition III LLC (CALLC III) an entity owned
by 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 GP interest was $10,600,000. This interest has
been classified as a noncontrolling interest included as a
separate component of equity in the Consolidated Balance Sheets
at March 31, 2009 and December 31, 2008.
CVR owns all of the interests in the Partnership (other than the
managing GP interest and the associated incentive distribution
rights (IDRs)) and is entitled to all cash
distributed by the Partnership except with respect to IDRs. The
managing general partner is not entitled to participate in
Partnership distributions except with respect to its IDRs, which
entitle the managing general partner to receive increasing
percentages (up to 48%) of the cash the Partnership distributes
in excess of $0.4313 per unit in a quarter. However, the
Partnership is not permitted to make any distributions with
respect to the IDRs until the aggregate Adjusted Operating
Surplus, as defined in the Partnerships partnership
agreement, generated by the Partnership through
December 31, 2009 has been distributed in respect of the
units held by CVR and any common units issued by the Partnership
if it elects to pursue an initial public offering. In addition,
the Partnership and its subsidiaries
5
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
are currently guarantors under the credit facility of
Coffeyville Resources, LLC (CRLLC), a wholly-owned
subsidiary of CVR. There will be no distributions paid with
respect to the IDRs for so long as the Partnership or its
subsidiaries are guarantors under the credit facility.
The Partnership is operated by CVRs senior management
pursuant to a services agreement among CVR, the managing general
partner, and the Partnership. The Partnership is managed by the
managing general partner and, to the extent described below,
CVR, as special general partner. As special general partner of
the Partnership, CVR has joint management rights regarding the
appointment, termination, and compensation of the chief
executive officer and chief financial officer of the managing
general partner, has the right to designate two members of the
board of directors of the managing general partner, and has
joint management rights regarding specified major business
decisions relating to the Partnership. CVR, the Partnership, and
the managing general partner also entered into a number of
agreements to regulate certain business relations between the
parties.
At March 31, 2009, the Partnership had 30,333 special LP
units outstanding, representing 0.1% of the total Partnership
units outstanding, and 30,303,000 special GP interests
outstanding, representing 99.9% of the total Partnership units
outstanding. In addition, the managing general partner owned the
managing GP interest and the IDRs. The managing general partner
contributed 1% of CRNFs interest to the Partnership in
exchange for its managing GP interest and the IDRs.
In accordance with the Contribution, Conveyance, and Assumption
Agreement, by and between the Partnership and the partners,
dated as of October 24, 2007, if an initial private or
public offering of the Partnership is not consummated by
October 24, 2009, the managing general partner of the
Partnership can require the Company to purchase the managing GP
interest. This put right expires on the earlier of
(1) October 24, 2012 or (2) the closing of the
Partnerships initial private or public offering. If the
Partnerships initial private or public offering is not
consummated by October 24, 2012, the Company has the right
to require the managing general partner to sell the managing GP
interest to the Company. This call right expires on the closing
of the Partnerships initial private or public offering. In
the event of an exercise of a put right or a call right, the
purchase price will be the fair market value of the managing GP
interest at the time of the purchase determined by an
independent investment banking firm selected by the Company and
the managing general partner.
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 (SEC). The consolidated
financial statements include the accounts of CVR and its
majority-owned direct and indirect subsidiaries. The ownership
interests of noncontrolling investors in its subsidiaries are
classified as a noncontrolling interest included as a separate
component of equity for all periods presented. All significant
intercompany account balances and transactions have been
eliminated in consolidation. Certain information and footnotes
required for the complete financial statements under GAAP have
been condensed or omitted pursuant to SEC rules and regulations.
These unaudited condensed consolidated financial statements
should be read in conjunction with the December 31, 2008
audited consolidated financial statements and notes thereto,
included in CVRs Annual Report on
Form 10-K
for the year ended December 31, 2008, which was filed with
the SEC on March 13, 2009.
In the opinion of the Companys management, the
accompanying unaudited condensed consolidated financial
statements reflect all adjustments (consisting only of normal
recurring adjustments) that are necessary to fairly present the
financial position of the Company as of March 31, 2009 and
December 31, 2008, the results of operations for the three
months ended March 31, 2009 and 2008, and the cash flows
for the three months ended March 31, 2009 and 2008.
6
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2009 or
any other interim period. The preparation of financial
statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses, and the disclosure
of contingent assets and liabilities. Actual results could
differ from those estimates.
As a result of the adoption of Statement of Financial Accounting
Standards (SFAS) No. 160,
Noncontrolling
Interests in Consolidated Financial Statements an
amendment of ARB No. 51,
on January 1, 2009, the
noncontrolling interest for the year ended December 31,
2008 has been properly reclassified to be included in the
Companys equity section of the Consolidated Balance Sheets.
|
|
(2)
|
Recent
Accounting Pronouncements
|
In June 2008, the Financial Accounting Standards Board
(FASB) issued FASB Staff Position (FSP)
Emerging Issues Task Force (EITF)
03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities
, which
became effective January 1, 2009 and is to be applied
retrospectively. Under the FSP, unvested share-based payment
awards which receive non-forfeitable dividend rights, or
dividend equivalents are considered participating securities and
are now required to be included in computing earnings per share
under the two class method. As required the Company adopted this
statement as of January 1, 2009. Based upon the nature of
the Companys share-based payment awards, it has been
determined that these awards are not participating securities
and therefore the FSP currently has no impact on the
Companys earnings per share calculations.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133.
This statement changes the disclosure
requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about how
and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
Statement 133 and its related interpretations, and how
derivative instruments and related hedge items affect an
entitys financial position, net earnings, and cash flows.
As required, the Company adopted this statement as of
January 1, 2009. As a result of the adoption, the Company
provided additional disclosures regarding its derivative
instruments in notes to the condensed consolidated financial
statements. There is no impact on the financial position or
results of operations of the Company as a result of this
adoption.
In February 2008, the FASB issued FASB Staff Position
157-2
which
defers the effective date of SFAS 157 for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in an entitys
financial statements on a recurring basis (at least annually).
As required, the Company adopted SFAS 157 as of
January 1, 2009. The adoption of SFAS 157 did not
impact the Companys financial position or earnings.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting standards
for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary is an ownership interest
in the consolidated entity that should be reported as equity in
the consolidated financial statements. SFAS 160 requires
retroactive adoption of the presentation and disclosure
requirements for existing noncontrolling interests. All other
requirements of SFAS 160 must be applied prospectively. The
Company adopted SFAS 160 effective January 1, 2009,
and as a result has classified the noncontrolling interest
(previously minority interest) as a separate component of equity
for all periods presented.
7
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(3)
|
Share-Based
Compensation
|
Prior to CVRs initial public offering in October 2007,
CVRs subsidiaries were held and operated by CALLC, a
limited liability company. Management of CVR holds an equity
interest in CALLC. CALLC issued non-voting override units to
certain management members who held common units of CALLC. There
were no required capital contributions for the override
operating units. In connection with CVRs initial public
offering, CALLC was split into two entities: CALLC and CALLC II.
In connection with this split, managements equity interest
in CALLC, including both their common units and non-voting
override units, was split so that half of managements
equity interest was in CALLC and half was in CALLC II. CALLC was
historically the primary reporting company and CVRs
predecessor. In addition, in connection with the transfer of the
managing GP interest of the Partnership to CALLC III in October
2007, CALLC III issued non-voting override units to certain
management members of CALLC III.
CVR, CALLC, CALLC II and CALLC III account for share-based
compensation in accordance with SFAS No. 123(R),
Share-Based Payments
and EITF Issue
No. 00-12,
Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee
(EITF 00-12).
CVR has been allocated non-cash share-based compensation expense
from CALLC, CALLC II and CALLC III.
In accordance with SFAS 123(R), CVR, CALLC, CALLC II and
CALLC III apply a fair-value based measurement method in
accounting for share-based compensation. In accordance with
EITF 00-12,
CVR recognizes the costs of the share-based compensation
incurred by CALLC, CALLC II and CALLC III on its behalf,
primarily in selling, general, and administrative expenses
(exclusive of depreciation and amortization), and a
corresponding capital contribution, as the costs are incurred on
its behalf, following the guidance in EITF Issue
No. 96-18,
Accounting for Equity Investments That Are Issued to Other
Than Employees for Acquiring, or in Conjunction with Selling
Goods or Services
, which requires remeasurement at each
reporting period through the performance commitment period, or
in CVRs case, through the vesting period.
At March 31, 2009, the value of the override units of CALLC
and CALLC II was derived from a probability-weighted expected
return method. The probability-weighted expected return method
involves a forward-looking analysis of possible future outcomes,
the estimation of ranges of future and present value under each
outcome, and the application of a probability factor to each
outcome in conjunction with the application of the current value
of the Companys common stock price with a Black-Scholes
option pricing formula, as remeasured at each reporting date
until the awards are vested.
The estimated fair value of the override units of CALLC III has
been determined using a probability-weighted expected return
method which utilizes CALLC IIIs cash flow projections,
which are representative of the nature of interests held by
CALLC III in the Partnership.
8
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table provides key information for the share-based
compensation plans related to the override units of CALLC, CALLC
II, and CALLC III. Compensation expense amounts are disclosed in
thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Compensation Expense Increase
|
|
|
|
|
|
|
|
|
|
|
|
(Decrease) for the
|
|
|
|
Benchmark
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Value
|
|
|
Awards
|
|
|
|
|
March 31,
|
|
Award Type
|
|
(per Unit)
|
|
|
Issued
|
|
|
Grant Date
|
|
2009
|
|
|
2008
|
|
|
Override Operating Units(a)
|
|
$
|
11.31
|
|
|
|
919,630
|
|
|
June 2005
|
|
$
|
584
|
|
|
$
|
(558
|
)
|
Override Operating Units(b)
|
|
$
|
34.72
|
|
|
|
72,492
|
|
|
December 2006
|
|
|
24
|
|
|
|
6
|
|
Override Value Units(c)
|
|
$
|
11.31
|
|
|
|
1,839,265
|
|
|
June 2005
|
|
|
1,187
|
|
|
|
533
|
|
Override Value Units(d)
|
|
$
|
34.72
|
|
|
|
144,966
|
|
|
December 2006
|
|
|
61
|
|
|
|
91
|
|
Override Units(e)
|
|
$
|
10.00
|
|
|
|
138,281
|
|
|
October 2007
|
|
|
|
|
|
|
|
|
Override Units(f)
|
|
$
|
10.00
|
|
|
|
642,219
|
|
|
February 2008
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,857
|
|
|
$
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
As CVRs common stock price increases or decreases,
compensation expense increases or is reversed in correlation
with the calculation of the fair value under the
probability-weighted expected return method.
|
Valuation
Assumptions
Significant assumptions used in the valuation of the Override
Operating Units (a) (b) were as follows:
|
|
|
|
|
|
|
|
|
|
|
(a) Override Operating Units
|
|
(b) Override Operating Units
|
|
|
March 31,
|
|
March 31,
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
|
None
|
|
None
|
CVR closing stock price
|
|
$5.54
|
|
$23.03
|
|
$5.54
|
|
$23.03
|
Estimated fair value
|
|
$10.77 per unit
|
|
$47.88 per unit
|
|
$2.62 per unit
|
|
$28.68 per unit
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
68.2%
|
|
N/A
|
|
68.2%
|
|
N/A
|
On the tenth anniversary of the issuance of override operating
units, such units convert into an equivalent number of override
value units. Override operating units are forfeited upon
termination of employment for cause. The explicit service period
for override operating unit recipients is based on the
forfeiture schedule below. In the event of all other
terminations of employment, the override operating units are
initially subject to forfeiture as follows:
|
|
|
|
|
Minimum
|
|
Forfeiture
|
|
Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
9
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Significant assumptions used in the valuation of the Override
Value Units (c) (d) were as follows:
|
|
|
|
|
|
|
|
|
|
|
(c) Override Value Units
|
|
(d) Override Value Units
|
|
|
March 31,
|
|
March 31,
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
|
6 years
|
|
6 years
|
CVR closing stock price
|
|
$5.54
|
|
$23.03
|
|
$5.54
|
|
$23.03
|
Estimated fair value
|
|
$5.17 per unit
|
|
$47.88 per unit
|
|
$2.62 per unit
|
|
$28.68 per unit
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
68.2%
|
|
N/A
|
|
68.2%
|
|
N/A
|
Unless the compensation committee of the board of directors of
CVR takes an action to prevent forfeiture, override value units
are forfeited upon termination of employment for any reason,
except that in the event of termination of employment by reason
of death or disability, all override value units are initially
subject to forfeiture as follows:
|
|
|
|
|
Minimum
|
|
Forfeiture
|
|
Period Held
|
|
Percentage
|
|
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
(e)
Override Units
In accordance with
SFAS 123(R),
Share-Based Compensation,
using a
binomial and a probability weighted expected return method which
utilized CALLC IIIs cash flows projections which includes
expected future earnings and the anticipated timing of IDRs, the
estimated grant date fair value of the override units was
approximately $3,000. In accordance with
EITF 00-12,
as a non-contributing investor, CVR also recognized income equal
to the amount that its interest in the investees net book
value has increased (that is its percentage share of the
contributed capital recognized by the investee) as a result of
the disproportionate funding of the compensation cost. As of
March 31, 2009 these units were fully vested. Significant
assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
Grant date valuation
|
|
$0.02 per unit
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
34.7%
|
(f)
Override Units
In accordance with
SFAS 123(R),
Share-Based Compensation,
using a
probability weighted expected return method which utilized CALLC
IIIs cash flows projections which includes expected future
earnings and the anticipated timing of IDRs, the estimated grant
date fair value of the override units was approximately $3,000.
In accordance with
EITF 00-12,
as a non-contributing investor, CVR also recognized income equal
to the amount that its interest in the investees net book
value has increased (that is its percentage share of the
contributed capital recognized by the investee) as a result of
the disproportionate funding of the compensation cost. Of the
642,219 units issued, 109,720 were immediately vested upon
10
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
issuance and the remaining units are subject to a forfeiture
schedule. Significant assumptions used in the valuation were as
follows:
|
|
|
|
|
|
|
March 31,
|
|
|
2009
|
|
2008
|
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived Service Period
|
|
Based on forfeiture schedule
|
|
Based on forfeiture schedule
|
Estimated fair value
|
|
$0.02 per unit
|
|
$0.004 per unit
|
Marketability and minority interest discount
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
47.0%
|
|
36.2%
|
At March 31, 2009, assuming no change in the estimated fair
value at March 31, 2009, there was approximately $4,161,000
of unrecognized compensation expense related to non-voting
override units. This is expected to be recognized over a
remaining period of approximately three years as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
|
|
Operating
|
|
|
Value
|
|
|
|
Units
|
|
|
Units
|
|
|
Nine months ending December 31, 2009
|
|
$
|
490
|
|
|
$
|
1,164
|
|
Year ending December 31, 2010
|
|
|
225
|
|
|
|
1,545
|
|
Year ending December 31, 2011
|
|
|
|
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
715
|
|
|
$
|
3,446
|
|
|
|
|
|
|
|
|
|
|
Phantom
Unit Plans
CVR, through a wholly-owned subsidiary, has two Phantom Unit
Appreciation Plans (the Phantom Unit Plans) whereby
directors, employees, and service providers may be awarded
phantom points at the discretion of the board of directors or
the compensation committee. Holders of service phantom points
have rights to receive distributions when holders of override
operating units receive distributions. Holders of performance
phantom points have rights to receive distributions when holders
of override value units receive distributions. There are no
other rights or guarantees, and the plan expires on
July 25, 2015 or at the discretion of the compensation
committee of the board of directors. As of March 31, 2009,
the issued Profits Interest (combined phantom points and
override units) represented 15% of combined common unit interest
and Profits Interest of CALLC and CALLC II. The Profits Interest
was comprised of approximately 11.1% and approximately 3.9% of
override interest and phantom interest, respectively. In
accordance with SFAS 123(R), the expense associated with
these awards for 2009 is based on the current fair value of the
awards which was derived from a probability weighted expected
return method. The probability weighted expected return method
involves a forward-looking analysis of possible future outcomes,
the estimation of ranges of future and present value under each
outcome, and the application of a probability factor to each
outcome in conjunction with the application of the current value
of the Companys common stock price with a Black-Scholes
option pricing formula, as remeasured at each reporting date
until the awards are settled. Based upon this methodology, the
service phantom interest and performance phantom interest were
valued at $10.77 and $5.17 per point, respectively, at
March 31, 2009. In accordance with SFAS 123(R), using
the March 31, 2008 CVR stock closing price to determine the
Companys equity value, through an independent valuation
process, the service phantom interest and performance phantom
interest were both valued at $47.88 per point. CVR has recorded
approximately $5,778,000 and $3,882,000 in personnel accruals as
of March 31, 2009 and December 31, 2008, respectively.
Compensation expense for the three months ended March 31,
2009 and 2008 related to the Phantom Unit Plans was $1,896,000
and $(547,000), respectively.
11
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At March 31, 2009, assuming no change in the estimated fair
value at March 31, 2009, there was approximately $1,493,000
of unrecognized compensation expense related to the Phantom Unit
Plans. This is expected to be recognized over a remaining period
of approximately three years.
Long
Term Incentive Plan
CVR has a Long Term Incentive Plan which permits the grant of
options, stock appreciation rights, or SARS, non-vested shares,
non-vested share units, dividend equivalent rights, share awards
and performance awards (including performance share units,
performance units and performance based restricted stock).
During the first quarter of 2009 there were no grants,
forfeitures or vesting of stock options or non-vested shares.
As of March 31, 2009, there was approximately $328,000 of
total unrecognized compensation cost related to non-vested
shares to be recognized over a weighted-average period of
approximately two and one-half years. Compensation expense
recorded for the three months ended March 31, 2009 and 2008
related to the non-vested stock was $67,000 and $56,000,
respectively. Compensation expense recorded for the three months
ended March 31, 2009 and 2008 related to the stock options
was $34,000 and $36,000, respectively.
Inventories consist primarily of crude oil, blending stock and
components, work in progress, fertilizer products, and refined
fuels and by-products. Inventories are valued at the lower of
the
first-in,
first-out (FIFO) cost, or market, for fertilizer
products, refined fuels and by-products for all periods
presented. Refinery unfinished and finished products inventory
values were determined using the
ability-to-bear
process, whereby raw materials and production costs are
allocated to
work-in-process
and finished products based on their relative fair values. Other
inventories, including other raw materials, spare parts, and
supplies, are valued at the lower of moving-average cost, which
approximates FIFO, or market. The cost of inventories includes
inbound freight costs.
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Finished goods
|
|
$
|
71,674
|
|
|
$
|
61,008
|
|
Raw materials and catalysts
|
|
|
64,238
|
|
|
|
45,928
|
|
In-process inventories
|
|
|
9,385
|
|
|
|
14,376
|
|
Parts and supplies
|
|
|
27,759
|
|
|
|
27,112
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
173,056
|
|
|
$
|
148,424
|
|
|
|
|
|
|
|
|
|
|
12
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(5)
|
Property,
Plant, and Equipment
|
A summary of costs for property, plant, and equipment is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Land and improvements
|
|
$
|
17,384
|
|
|
$
|
17,383
|
|
Buildings
|
|
|
22,852
|
|
|
|
22,851
|
|
Machinery and equipment
|
|
|
1,297,132
|
|
|
|
1,288,782
|
|
Automotive equipment
|
|
|
8,877
|
|
|
|
7,825
|
|
Furniture and fixtures
|
|
|
7,907
|
|
|
|
7,835
|
|
Leasehold improvements
|
|
|
1,081
|
|
|
|
1,081
|
|
Construction in progress
|
|
|
56,563
|
|
|
|
53,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,411,796
|
|
|
|
1,399,684
|
|
Accumulated depreciation
|
|
|
241,468
|
|
|
|
220,719
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,170,328
|
|
|
$
|
1,178,965
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest recognized as a reduction in interest
expense for the three months ended March 31, 2009 and
March 31, 2008 totaled approximately $413,000 and
$1,118,000, respectively. Land and buildings that are under a
capital lease obligation approximated $4,827,000 as of
March 31, 2009 and December 31, 2008. Amortization of
assets held under capital leases is included in depreciation
expense.
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 $711,000 and $600,000 for the three months ended
March 31, 2009 and 2008, respectively.
Direct operating expenses (exclusive of depreciation and
amortization) includes direct costs of labor, maintenance and
services, energy and utility costs, environmental compliance
costs as well as chemicals and catalysts and other direct
operating expenses. Direct operating expenses excludes
depreciation and amortization of $19,742,000 and $18,703,000 for
the three months ended March 31, 2009 and 2008,
respectively.
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 $456,000 and $332,000 for the three months ended
March 31, 2009 and 2008, respectively.
|
|
(7)
|
Note
Payable and Capital Lease Obligation
|
The Company entered into an insurance premium finance agreement
with Cananwill, Inc. in July 2008 to finance a portion of the
purchase of its property, liability, cargo and terrorism
policies. The original balance of the note provided by the
Company under such agreement was $10,000,000. This note is to be
repaid in equal installments with the final payment due in June
2009. As of March 31, 2009 and December 31, 2008, the
Company owed $3,750,000 and $7,500,000, respectively, related to
this note.
The Company also entered into a capital lease for real property
used for corporate purposes on May 29, 2008. The lease has
an initial lease term of one year with an option to renew for
three additional one-year periods. The Company has the option to
purchase the property during the initial lease term or during
the renewal periods if the lease is renewed. In connection with
the capital lease the Company recorded a capital
13
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
asset and capital lease obligation of $4,827,000. The capital
lease obligation was $4,071,000 and $4,043,000 as of
March 31, 2009 and December 31, 2008, respectively.
|
|
(8)
|
Flood,
Crude Oil Discharge and Insurance Related Matters
|
For the three months ended March 31, 2009 and 2008, the
Company recorded pretax expenses, net of anticipated insurance
recoveries of $181,000 and $5,763,000, respectively, associated
with the June/July 2007 flood and associated crude oil
discharge. The costs are reported in net costs associated with
flood in the Consolidated Statements of Operations. Total
accounts receivable from insurance was $1,000,000 at
March 31, 2009 and $12,756,000 as of December 31,
2008. With the final insurance proceeds received under the
Companys property insurance policy and builders risk
policy during the first quarter of 2009, in the amount of
$11,756,000, all property insurance claims and builders
risk claims were fully settled with all remaining claims closed.
The receivable balance at March 31, 2009 is associated with
the crude oil discharge. See Note 11 (Commitments and
Contingent Liabilities) for additional information
regarding environmental and other contingencies related to the
crude oil discharge that occurred on July 1, 2007.
As of March 31, 2009, the remaining receivable from
insurers was not anticipated to be collected in the next twelve
months, and therefore has been classified as a non-current
asset. Management believes the recovery of the receivable from
the insurance carriers is probable.
As of March 31, 2009, the Company did not have any
unrecognized tax benefits and did not have an accrual for any
amounts for interest or penalties related to uncertain tax
positions. The Companys accounting policy with respect to
interest and penalties related to tax uncertainties is to
classify these amounts as income taxes.
CVR and its subsidiaries file U.S. federal and various
state income and franchise tax returns. The Companys
U.S. federal and state tax years subject to examination as
of March 31, 2009 are 2005 to 2008.
The Companys effective tax rate for the three months ended
March 31, 2009 and 2008 was 28.1% and 23.6%, respectively,
as compared to the Companys combined federal and state
expected statutory tax rate of 39.7%. The effective tax rate is
lower than the expected statutory tax rate for the three months
ended March 31, 2009 and 2008, respectively, due primarily
to federal income tax credits available to small business
refiners related to the production of ultra low sulfur diesel
fuel and Kansas state incentives generated under the High
Performance Incentive Program.
14
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Basic and diluted earnings per share are computed by dividing
net income by weighted average common shares outstanding. The
components of the basic and diluted earnings per share
calculation are as follows:
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(in thousands, except share data)
|
|
|
Net income
|
|
$
|
30,661
|
|
|
$
|
22,221
|
|
Weighted average common shares outstanding
|
|
|
86,243,745
|
|
|
|
86,141,291
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
Non-vested common stock
|
|
|
78,666
|
|
|
|
17,500
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding assuming dilution
|
|
|
86,322,411
|
|
|
|
86,158,791
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$
|
0.36
|
|
|
$
|
0.26
|
|
Diluted earnings per share
|
|
$
|
0.36
|
|
|
$
|
0.26
|
|
Outstanding stock options totaling 32,350 and 18,900 common
shares were excluded from the diluted earnings per share
calculation for the three months ended March 31, 2009 and
2008, respectively, as they were antidilutive.
|
|
(11)
|
Commitments
and Contingent Liabilities
|
The minimum required payments for the Companys lease
agreements and unconditional purchase obligations are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Unconditional
|
|
|
|
Leases
|
|
|
Purchase Obligations
|
|
|
Nine months ending December 31, 2009
|
|
$
|
3,369
|
|
|
$
|
22,311
|
|
Year ending December 31, 2010
|
|
|
3,783
|
|
|
|
36,044
|
|
Year ending December 31, 2011
|
|
|
2,377
|
|
|
|
57,407
|
|
Year ending December 31, 2012
|
|
|
1,983
|
|
|
|
54,689
|
|
Year ending December 31, 2013
|
|
|
1,089
|
|
|
|
54,577
|
|
Thereafter
|
|
|
270
|
|
|
|
360,735
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,871
|
|
|
$
|
585,763
|
|
|
|
|
|
|
|
|
|
|
The Company leases various equipment, including rail cars, and
real properties under long-term operating leases, expiring at
various dates. In the normal course of business, the Company
also has long-term commitments to purchase services such as
natural gas, electricity, water and transportation services. For
the three months ended March 31, 2009 and 2008, lease
expense totaled $1,190,000 and $1,071,000, respectively. The
lease agreements have various remaining terms. Some agreements
are renewable, at the Companys option, for additional
periods. It is expected, in the ordinary course of business,
that leases will be renewed or replaced as they expire.
From time to time, the Company is involved in various lawsuits
arising in the normal course of business, including matters such
as those described below under Environmental, Health, and
Safety (EHS) Matters. Liabilities related to
such litigation are recognized when the related costs are
probable and can be reasonably estimated. Management believes
the Company has accrued for losses for which it may ultimately
be responsible. It is possible that managements estimates
of the outcomes will change within the next year due to
uncertainties inherent in litigation and settlement
negotiations. In the opinion of management, the ultimate
15
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. In connection with that
discharge, the Company received in May 2008 notices of claims
from sixteen private claimants under the Oil Pollution Act in
aggregate amount of approximately $4,393,000. In August 2008,
those claimants filed suit against the Company in the United
States District Court for the District of Kansas in Wichita. The
Company believes that the resolution of these claims will not
have a material adverse effect on the consolidated financial
statements.
As a result of the crude oil discharge that occurred on
July 1, 2007, the Company entered into an administrative
order on consent (the Consent Order) with the
Environmental Protection Agency (EPA) on
July 10, 2007. As set forth in the Consent Order, the EPA
concluded that the discharge of oil from the Companys
refinery caused and may continue to cause an imminent and
substantial threat to the public health and welfare. Pursuant to
the Consent Order, the Company agreed to perform specified
remedial actions to respond to the discharge of crude oil from
the Companys refinery. The substantial majority of all
known remedial actions were completed by January 31, 2009.
The Company is currently preparing its final report to the EPA
to satisfy the final requirement of the Consent Order. The
Company anticipates that the final report will be provided by
June 2009, with no further requirements resulting from the
review of the report that could be material to the
Companys business, financial condition, or results of
operations.
As of March 31, 2009, the total gross costs recorded
associated with remediation and third party property damage as a
result of the crude oil discharge approximated $54,327,000. The
Company has not estimated or accrued for any potential fines,
penalties or claims that may be imposed or brought by regulatory
authorities or possible additional damages arising from lawsuits
related to the June/July 2007 flood as management does not
believe any such fines, penalties or lawsuits would be material
nor can be estimated.
The Company is seeking insurance coverage for this release and
for the ultimate costs for remediation and property damage
claims. On July 10, 2008, the Company filed two lawsuits in
the United States District Court for the District of Kansas
against certain of the Companys insurance carriers with
regard to the Companys insurance coverage for the
June/July 2007 flood and crude oil discharge. The Companys
excess environmental liability insurance carrier has asserted
that its pollution liability claims are for cleanup,
which is not covered by such policy, rather than for
property damage, which is covered to the limits of
the policy. While the Company will vigorously contest the excess
carriers position, it contends that if that position were
upheld, the umbrella Comprehensive General Liability policies
would continue to provide coverage for these claims. Each
insurer, however, has reserved its rights under various policy
exclusions and limitations and has cited potential coverage
defenses. Although the Company believes that certain amounts
under the environmental and liability insurance policies will be
recovered, the Company cannot be certain of the ultimate amount
or timing of such recovery because of the difficulty inherent in
projecting the ultimate resolution of the Companys claims.
The lawsuit with the insurance carriers under the environmental
liability and comprehensive general liability policies remains
the only unsettled lawsuit with the insurance carriers. The
property insurance lawsuit has been settled and dismissed.
Environmental,
Health, and Safety (EHS) Matters
Coffeyville Resources Refining & Marketing, LLC
(CRRM), Coffeyville Resources Crude Transportation,
LLC (CRCT) and Coffeyville Resources Terminal, LLC
(CRT), all of which are wholly-owned subsidiaries of
CVR, and CRNF are subject to various stringent federal, state,
and local EHS rules and
16
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
regulations. Liabilities related to EHS matters are recognized
when the related costs are probable and can be reasonably
estimated. Estimates of these costs are based upon currently
available facts, existing technology, site-specific costs, and
currently enacted laws and regulations. In reporting EHS
liabilities, no offset is made for potential recoveries. Such
liabilities include estimates of the Companys share of
costs attributable to potentially responsible parties which are
insolvent or otherwise unable to pay. EHS liabilities are
monitored and adjusted regularly as new facts emerge or changes
in law or technology occur.
CRRM, CRNF, CRCT and CRT own and/or operate manufacturing and
ancillary operations at various locations directly related to
petroleum refining and distribution and nitrogen fertilizer
manufacturing. Therefore, CRRM, CRNF, CRCT and CRT have exposure
to potential EHS liabilities related to past and present EHS
conditions at some of these locations.
CRRM and CRT have agreed to perform corrective actions at the
Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal
facility, pursuant to Administrative Orders on Consent issued
under the Resource Conservation and Recovery Act
(RCRA) to address historical contamination by the
prior owners (RCRA Docket
No. VII-94-H-0020
and Docket
No. VII-95-H-011,
respectively). In 2005, CRNF agreed to participate in the State
of Kansas Voluntary Cleanup and Property Redevelopment Program
(VCPRP) to address a reported release of urea
ammonium nitrate (UAN) at its UAN loading rack. As
of March 31, 2009 and December 31, 2008, environmental
accruals of $6,541,000 and $6,924,000, 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 $2,601,000 and $2,684,000, respectively,
included in other current liabilities. The Companys
accruals were determined based on an estimate of payment costs
through 2031, for which the scope of remediation was arranged
with the EPA, and were discounted at the appropriate risk free
rates at March 31, 2009 and December 31, 2008,
respectively. The accruals include estimated closure and
post-closure costs of $1,545,000 and $1,124,000 for two
landfills at March 31, 2009 and December 31, 2008,
respectively. The estimated future payments for these required
obligations are as follows (in thousands):
|
|
|
|
|
|
|
Amount
|
|
|
Nine months ending December 31, 2009
|
|
$
|
2,348
|
|
Year ending December 31, 2010
|
|
|
1,013
|
|
Year ending December 31, 2011
|
|
|
516
|
|
Year ending December 31, 2012
|
|
|
313
|
|
Year ending December 31, 2013
|
|
|
313
|
|
Thereafter
|
|
|
2,682
|
|
|
|
|
|
|
Undiscounted total
|
|
|
7,185
|
|
Less amounts representing interest at 2.37%
|
|
|
644
|
|
|
|
|
|
|
Accrued environmental liabilities at March 31, 2009
|
|
$
|
6,541
|
|
|
|
|
|
|
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.
In February 2000, the EPA promulgated the Tier II Motor
Vehicle Emission Standards Final Rule for all passenger
vehicles, establishing standards for sulfur content in gasoline
that were required to be met by 2006. In addition, in January
2001, the EPA promulgated its on-road diesel regulations, which
required a 97% reduction in the sulfur content of diesel sold
for highway use by June 1, 2006, with full compliance by
January 1, 2010. In February 2004, the EPA granted the
Company approval under a hardship waiver that would
defer meeting final Ultra Low Sulfur Gasoline (ULSG)
standards and Ultra Low Sulfur Diesel (ULSD)
requirements. The hardship waiver was revised at CRRMs
request on September 25, 2008. The
17
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company met the conditions of the hardship waiver
related to the ULSD requirements in late 2006 and is continuing
its work related to meeting its compliance date with ULSG
standards in accordance with the revised hardship waiver.
Compliance with the Tier II gasoline and on-road diesel
standards required us to spend approximately $13,787,000 during
2008, approximately $16,800,000 during 2007 and $79,033,000
during 2006. Based on information currently available, CRRM and
CRT anticipate spending approximately $24.5 million in
2009, $20.2 million in 2010, and $5.0 million in 2011
to comply with ULSG requirements and improve operational
reliability. The entire amounts are expected to be capitalized.
For the three-months ended March 31, 2009 and 2008, CVR has
spent $3,450,000 and $1,941,000, respectively.
Environmental expenditures are capitalized when such
expenditures are expected to result in future economic benefits.
For the three months ended March 31, 2009 and 2008, capital
environmental expenditures were $3,963,000 and $15,473,000,
respectively. These expenditures were incurred to improve the
environmental compliance and efficiency of the operations.
CRRM, CRNF, CRCT and CRT believe they are in substantial
compliance with existing EHS rules and regulations. There can be
no assurance that the EHS matters described above or other EHS
matters which may develop in the future will not have a material
adverse effect on the Companys business, financial
condition, or results of operations.
|
|
(12)
|
Fair
Value Measurements
|
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
. This statement established a
single authoritative definition of fair value when accounting
rules require the use of fair value, set out a framework for
measuring fair value, and required additional disclosures about
fair value measurements. SFAS 157 clarifies that fair value
is an exit price, representing the amount that would be received
to sell an asset or paid to transfer a liability in an orderly
transaction between market participants.
SFAS 157 discusses valuation techniques, such as the market
approach (prices and other relevant information generated by
market conditions involving identical or comparable assets or
liabilities), the income approach (techniques to convert future
amounts to single present amounts based on market expectations
including present value techniques and option-pricing), and the
cost approach (amount that would be required to replace the
service capacity of an asset which is often referred to as
replacement cost). SFAS 157 utilizes a fair value hierarchy
that prioritizes the inputs to valuation techniques used to
measure fair value into three broad levels. The following is a
brief description of those three levels:
|
|
|
|
|
Level 1 Quoted prices in active market for
identical assets and liabilities
|
|
|
|
Level 2 Other significant observable inputs
(including quoted prices in active markets for similar assets or
liabilities)
|
|
|
|
Level 3 Significant unobservable inputs
(including the Companys own assumptions in determining the
fair value)
|
The following table sets forth the assets and liabilities
measured at fair value on a recurring basis, by input level, as
of March 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Receivable from swap counterparty current (Cash Flow
Swap)
|
|
|
|
|
|
$
|
18,355
|
|
|
|
|
|
|
$
|
18,355
|
|
Receivable from swap counterparty non-current (Cash
Flow Swap)
|
|
|
|
|
|
|
2,433
|
|
|
|
|
|
|
|
2,433
|
|
Other current liabilities (Interest Rate Swap)
|
|
|
|
|
|
|
(5,018
|
)
|
|
|
|
|
|
|
(5,018
|
)
|
Other long-term liabilities (Interest Rate Swap)
|
|
|
|
|
|
|
(1,254
|
)
|
|
|
|
|
|
|
(1,254
|
)
|
18
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of March 31, 2009, the only financial assets and
liabilities that are measured at fair value on a recurring basis
are the Companys derivative instruments. See Note 13
(Derivative Financial Instruments) for a discussion
of the Cash Flow Swap and Interest Rate Swap. The Companys
derivative contracts giving rise to assets or liabilities under
Level 2 are valued using pricing models based on other
significant observable inputs.
|
|
(13)
|
Derivative
Financial Instruments
|
Gain (loss) on derivatives, net consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain (loss) on cash flow swap agreements
|
|
$
|
(15,714
|
)
|
|
$
|
(21,516
|
)
|
Unrealized gain (loss) on cash flow swap agreements
|
|
|
(20,114
|
)
|
|
|
(13,907
|
)
|
Realized gain (loss) on other agreements
|
|
|
(1,003
|
)
|
|
|
(7,993
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
163
|
|
|
|
1,157
|
|
Realized gain (loss) on interest rate swap agreements
|
|
|
(1,710
|
)
|
|
|
522
|
|
Unrealized gain (loss) on interest rate swap agreements
|
|
|
1,517
|
|
|
|
(6,134
|
)
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives, net
|
|
$
|
(36,861
|
)
|
|
$
|
(47,871
|
)
|
|
|
|
|
|
|
|
|
|
CVR is subject to price fluctuations caused by supply and demand
conditions, weather, economic conditions, interest rate
fluctuations and other factors. To manage price risk on crude
oil and other inventories and to fix margins on certain future
production, the Company may enter into various derivative
transactions. The Company, as further described below, entered
into certain commodity derivative contracts (i.e., the Cash Flow
Swap) and an interest rate swap as required by the long-term
debt agreements. The commodity derivative is for the purpose of
managing price risk on crude oil and finished goods and the
interest rate swap is for the purpose of managing interest rate
risk.
CVR has adopted SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities
which imposes
extensive record-keeping requirements in order to designate a
derivative financial instrument as a hedge. CVR holds derivative
instruments, such as exchange-traded crude oil futures, certain
over-the-counter
forward swap agreements and interest rate swap agreements, which
it believes provide an economic hedge on future transactions,
but such instruments are not designated as hedges. Gains or
losses related to the change in fair value and periodic
settlements of these derivative instruments are classified as
gain (loss) on derivatives, net in the Consolidated Statements
of Operations.
Cash
Flow Swap
At March 31, 2009, CVRs Petroleum Segment held
commodity derivative contracts (the Cash Flow Swap)
for the period from July 1, 2005 to June 30, 2010 with
a related party. See Note 14 (Related Party
Transactions). The Cash Flow Swap agreements were
originally executed on June 16, 2005 in conjunction with
the acquisition by CALLC of all the outstanding stock held by
Coffeyville Group Holdings, LLC and were required under the
terms of the long-term debt agreements. The notional quantities
on the date of execution were 100,911,000 barrels of crude
oil, 2,348,802,750 gallons of unleaded gasoline and
1,889,459,250 gallons of heating oil. The Cash Flow Swap
agreements were executed at the prevailing market rate at the
time of execution. At March 31, 2009, the notional open
amounts under the swap agreements were 11,846,250 barrels
of crude oil, 248,771,250 gallons of unleaded gasoline and
248,771,250 gallons of heating oil. These positions are marked
to market at each reporting date and result in unrealized gains
(losses) using a valuation method that utilizes quoted market
prices and assumptions. All unrealized gains and losses are
currently recognized in the Companys Consolidated
Statements of Operations. The realized gain or loss from
19
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Cash Flow Swap is settled quarterly. All of the activity
related to the commodity derivative contracts is reported in the
Petroleum Segment.
As noted above, the counterparty to the Companys Cash Flow
Swap agreement is a related party. As prudent, the Company from
time-to-time
considers counterparty credit risk. The maximum amount of loss
due to the credit risk of the counterparty, should the
counterparty fail to perform according to the terms of the
contracts, is contingent upon the unsettled portion of the
hedge, if any. For the Company to be at-risk the
unsettled portion of the hedge would need to be in a net
receivable position. Based upon the quoted market prices as of
March 31, 2009, the Company recorded a current and
non-current receivable related to the Cash Flow Swap. As such,
all or a portion of the receivable could be at-risk
should the counterparty fail to perform. The Company has
provided a letter of credit totaling $150,000,000, issued in
support of the Cash Flow Swap.
Interest
Rate Swap
At March 31, 2009, CRLLC held derivative contracts known as
Interest Rate Swap agreements (the Interest Rate
Swap) that converted CRLLCs floating-rate bank debt
into 4.195% fixed-rate debt on a notional amount of
$180,000,000. Half of the Interest Rate Swap 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 agreement. The Interest Rate Swap
agreements carry the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Fixed
|
|
Period Covered
|
|
Amount
|
|
|
Interest Rate
|
|
|
March 31, 2009 to March 30, 2010
|
|
$
|
180 million
|
|
|
|
4.195
|
%
|
March 31, 2010 to June 30, 2010
|
|
|
110 million
|
|
|
|
4.195
|
%
|
CVR pays the fixed rates listed above and receives a floating
rate based on three month LIBOR rates, with payments calculated
on the notional amounts listed above. The notional amounts do
not represent actual amounts exchanged by the parties but
instead represent the amounts on which the contracts are based.
The Interest Rate Swap results in both realized and unrealized
gains or losses and is included in the Companys
Consolidated Statements of Operations. The realized gain or loss
from the Interest Rate Swap is settled quarterly. The Interest
Rate Swap is marked to market each reporting date. Transactions
related to the interest rate swap agreements are not allocated
to the Petroleum or Nitrogen Fertilizer segments.
The Interest Rate Swap has two counterparties. As noted above,
one half of the Interest Rate Swap agreements are held with a
related party. As of March 31, 2009, both counterparties
had an investment-grade debt rating. The maximum amount of loss
due to the credit risk of the counterparty, should the
counterparty fail to perform according to the terms of the
contracts, is contingent upon the unsettled portion of the
hedge, if any. For the Company to be at-risk the
unsettled portion of the hedge would need to be in a net
receivable position. As of March 31, 2009, the
Companys Interest Rate Swap was in a payable position and
thus would not be considered at-risk as it relates
to risk posed by the swap counterparties.
|
|
(14)
|
Related
Party Transactions
|
The Goldman Sachs Funds, or GS, and the Kelso Funds, or Kelso
together own a majority of the common stock of the Company.
Cash
Flow Swap
CRLLC entered into certain crude oil, heating oil and gasoline
swap agreements (referred to above and herein as the Cash Flow
Swap) with J. Aron & Company (J. Aron), a
subsidiary of GS. These agreements were entered into on
June 16, 2005, with an expiration date of June 30,
2010 (as described in Note 13,
20
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Derivative Financial Instruments). Realized and
unrealized losses totaling $35,828,000 and $35,423,000 were
recognized related to these swap agreements for the three months
ended March 31, 2009 and 2008, respectively, and are
reflected in gain (loss) on derivatives, net in the Consolidated
Statements of Operations. In addition, the Consolidated Balance
Sheet at March 31, 2009, includes an asset of $18,355,000
included in current receivable from swap counterparty and
$2,433,000 included in long-term receivable from swap
counterparty. Also reflected in the Consolidated Balance Sheet
at March 31, 2009 is a payable to swap counterparty for
$15,714,000. This amount represents the realized loss on the
Cash Flow Swap for the three months ended March 31, 2009.
As of December 31, 2008, the Company recorded short-term
and long-term receivable from swap counterparty of $32,630,000
and $5,632,000, respectively, for the unrealized gain on the
Cash Flow Swap as of December 31, 2008.
J.
Aron Deferrals
As a result of the June/July 2007 flood and the related
temporary cessation of business operations, the Company entered
into deferral agreements for amounts owed to J. Aron under the
Cash Flow Swap discussed above. The amount deferred, excluding
accrued interest, totaled $123,681,000. Of the deferred
balances, $61,306,000 had been repaid as of December 31,
2008. The remaining deferred liability is included in the
Consolidated Balance Sheet at December 31, 2008 in payable
to swap counterparty, as it was ultimately deferred to July
2009. Accrued interest related to the deferral agreement for the
year ended December 31, 2008 totaled $202,000 and is
included in other current liabilities. Interest expense related
to the deferral agreement totaled $307,000 and $1,249,000 for
the three months ended March 31, 2009 and 2008,
respectively.
In the first quarter of 2009, the Company repaid the entire
remaining deferral obligation of $62,375,000, including accrued
interest of $509,000, resulting in the Company being released
from any and all of its obligations under the deferral
agreements.
Interest
Rate Swap
On June 30, 2005, the Company also entered into three
Interest Rate Swap agreements (referred to above as the Interest
Rate Swap) with J. Aron (as described in Note 13,
Derivative Financial Instruments). Losses totaling
$97,000 and $2,813,000 were recognized related to these swap
agreements for the three months ended March 31, 2009 and
2008, respectively, and are reflected in gain (loss) on
derivatives, net in the Consolidated Statements of Operations.
In addition, the Consolidated Balance Sheets at March 31,
2009 and December 31, 2008 includes $2,508,000 and
$2,595,000, respectively, in other current liabilities and
$627,000 and $1,298,000, respectively, in other long-term
liabilities related to the same agreements.
Crude
Oil Supply Agreement
During 2008, the Company was a counterparty to a crude oil
supply agreement with J. Aron. Under the agreement, the parties
agreed to negotiate the cost of each barrel of crude oil to be
purchased from a third party, and CRRM agreed to pay J. Aron a
fixed supply service fee per barrel over the negotiated cost of
each barrel of crude purchased. The cost was adjusted further
using a spread adjustment calculation based on the time period
the crude oil was estimated to be delivered to the refinery,
other market conditions, and other factors deemed appropriate.
The Company recorded $0 and $8,211,000 on the Consolidated
Balance Sheets at March 31, 2009 and December 31,
2008, respectively, in prepaid expenses and other current assets
for the prepayment of crude oil. In addition, $0 and $20,063,000
were recorded in inventory and $0 and $2,757,000 were recorded
in accounts payable at March 31, 2009 and December 31,
2008, respectively. Expenses associated with this agreement
included in cost of product sold (exclusive of depreciation and
amortization) for the three months ended March 31, 2009 and
2008 totaled $0 and $766,213,000, respectively. The crude oil
supply agreement was terminated with J. Aron effective
December 31, 2008. The Company entered
21
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
into a new crude oil supply agreement with Vitol Inc., an
unrelated party, effective December 31, 2008, with a
termination date two years from the effective date.
Cash
and Cash Equivalents
The Company opened a highly liquid money market account with
average maturities of less than 90 days within the Goldman
Sachs fund family in September 2008. As of March 31, 2009
and December 31, 2008, the balance in the account was
approximately $17,664,000 and $149,000, respectively. For the
three months ended March 31, 2009, the account earned
interest income of $16,000.
Other
For the three months ended March 31, 2009, the Company
purchased approximately $77,000 of Fluid Catalytic Cracking Unit
additives from Intercat, Inc. A director of the Company,
Mr. Regis Lippert, is also the Director, President, CEO and
majority shareholder of Intercat, Inc.
(15) Business
Segments
CVR measures segment profit as operating income for Petroleum
and Nitrogen Fertilizer, CVRs two reporting segments,
based on the definitions provided in SFAS No. 131,
Disclosures about Segments of an Enterprise and Related
Information
. All operations of the segments are located
within the United States.
Petroleum
Principal products of the Petroleum Segment are refined fuels,
propane, and petroleum refining by-products including pet coke.
CVR sells the pet coke to the Partnership for use in the
manufacturing of nitrogen fertilizer at the adjacent nitrogen
fertilizer plant. For CVR, a per-ton transfer price is used to
record intercompany sales on the part of the Petroleum Segment
and corresponding intercompany cost of product sold (exclusive
of depreciation and amortization) for the Nitrogen Fertilizer
Segment. The per ton transfer price paid, pursuant to the pet
coke supply agreement that became effective October 24,
2007, is based on the lesser of a pet coke price derived from
the price received by the fertilizer segment for UAN (subject to
a UAN based price ceiling and floor) and a pet coke price index
for pet coke. The intercompany transactions are eliminated in
the Other Segment. Intercompany sales included in petroleum net
sales were $3,018,000 and $2,806,000 for the three months ended
March 31, 2009 and 2008, respectively.
Intercompany cost of product sold (exclusive of depreciation and
amortization) for the hydrogen sales described below under
Nitrogen Fertilizer was $658,000 and $5,291,000 for
the three months ended March 31, 2009 and 2008,
respectively.
Nitrogen
Fertilizer
The principal product of the Nitrogen Fertilizer Segment is
nitrogen fertilizer. Intercompany cost of product sold
(exclusive of depreciation and amortization) for the pet coke
transfer described above was $3,536,000 and $2,545,000 for the
three months ended March 31, 2009 and 2008, respectively.
Sales of hydrogen to the Petroleum Segment have been reflected
as net sales for the Nitrogen Fertilizer Segment. For the three
months ended March 31, 2009 and 2008, the net sales
generated from intercompany hydrogen sales were $658,000 and
$5,291,000, respectively. These intercompany transactions are
eliminated in the Other Segment.
22
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Segment
The Other Segment reflects intercompany eliminations, including
significant intercompany eliminations of receivables and
payables between the segments, cash and cash equivalents, all
debt related activities, income tax activities and other
corporate activities that are not allocated to the operating
segments.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(in thousands)
|
|
|
Net sales
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
545,282
|
|
|
$
|
1,168,500
|
|
Nitrogen Fertilizer
|
|
|
67,789
|
|
|
|
62,600
|
|
Intersegment eliminations
|
|
|
(3,676
|
)
|
|
|
(8,097
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
609,395
|
|
|
$
|
1,223,003
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
417,598
|
|
|
$
|
1,035,085
|
|
Nitrogen Fertilizer
|
|
|
8,682
|
|
|
|
8,945
|
|
Intersegment eliminations
|
|
|
(4,675
|
)
|
|
|
(7,836
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
421,605
|
|
|
$
|
1,036,194
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
34,622
|
|
|
$
|
40,290
|
|
Nitrogen Fertilizer
|
|
|
21,612
|
|
|
|
20,266
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
56,234
|
|
|
$
|
60,556
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
181
|
|
|
$
|
5,533
|
|
Nitrogen Fertilizer
|
|
|
|
|
|
|
(17
|
)
|
Other
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
181
|
|
|
$
|
5,763
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
15,878
|
|
|
$
|
14,877
|
|
Nitrogen Fertilizer
|
|
|
4,616
|
|
|
|
4,477
|
|
Other
|
|
|
415
|
|
|
|
281
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
20,909
|
|
|
$
|
19,635
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
64,659
|
|
|
$
|
63,618
|
|
Nitrogen Fertilizer
|
|
|
29,282
|
|
|
|
26,017
|
|
Other
|
|
|
(2,981
|
)
|
|
|
(2,277
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
90,960
|
|
|
$
|
87,358
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
7,392
|
|
|
$
|
22,541
|
|
Nitrogen Fertilizer
|
|
|
7,431
|
|
|
|
2,817
|
|
Other
|
|
|
1,095
|
|
|
|
798
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,918
|
|
|
$
|
26,156
|
|
|
|
|
|
|
|
|
|
|
23
CVR
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of March 31,
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(in thousands)
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,038,208
|
|
|
$
|
1,032,223
|
|
Nitrogen Fertilizer
|
|
|
671,603
|
|
|
|
644,301
|
|
Other
|
|
|
(134,008
|
)
|
|
|
(66,041
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,575,803
|
|
|
$
|
1,610,483
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
|
|
|
$
|
|
|
Nitrogen Fertilizer
|
|
|
40,969
|
|
|
|
40,969
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
40,969
|
|
|
$
|
40,969
|
|
|
|
|
|
|
|
|
|
|
24
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion and analysis should be read in
conjunction with the consolidated financial statements and
related notes and with the statistical information and financial
data appearing in this Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2009 as well as our Annual
Report on
Form 10-K
for the year ended December 31, 2008. Results of operations
for the three months ended March 31, 2009 are not
necessarily indicative of results to be attained for any other
period.
Forward-Looking
Statements
This
Form 10-Q,
including this Managements Discussion and Analysis of
Financial Condition and Results of Operations, contains
forward-looking statements as defined by the
Securities and Exchange Commission (the SEC). Such
statements are those concerning contemplated transactions and
strategic plans, expectations and objectives for future
operations. These include, without limitation:
|
|
|
|
|
statements, other than statements of historical fact, that
address activities, events or developments that we expect,
believe or anticipate will or may occur in the future;
|
|
|
|
statements relating to future financial performance, future
capital sources and other matters; and
|
|
|
|
any other statements preceded by, followed by or that include
the words anticipates, believes,
expects, plans, intends,
estimates, projects, could,
should, may, or similar expressions.
|
Although we believe that our plans, intentions and expectations
reflected in or suggested by the forward-looking statements we
make in this
Form 10-Q,
including this Managements Discussion and Analysis of
Financial Condition and Results of Operations, are reasonable,
we can give no assurance that such plans, intentions or
expectations will be achieved. These statements are based on
assumptions made by us based on our experience and perception of
historical trends, current conditions, expected future
developments and other factors that we believe are appropriate
in the circumstances. Such statements are subject to a number of
risks and uncertainties, many of which are beyond our control.
You are cautioned that any such statements are not guarantees of
future performance and actual results or developments may differ
materially from those projected in the forward-looking
statements as a result of various factors, including but not
limited to those set forth under Risk Factors in our
Annual Report on
Form 10-K
for the year ended December 31, 2008. Such factors include,
among others:
|
|
|
|
|
volatile petroleum products resulting in volatile refining
margins;
|
|
|
|
exposure to the risks associated with volatile crude prices;
|
|
|
|
the availability of adequate cash and other sources of liquidity
for our capital needs;
|
|
|
|
disruption of our ability to obtain an adequate supply of crude
oil;
|
|
|
|
losses due to the Cash Flow Swap;
|
|
|
|
interruption of the pipelines supplying feedstock and in the
distribution of our products;
|
|
|
|
competition in the petroleum and nitrogen fertilizer businesses;
|
|
|
|
continued significant declines in natural gas prices, which
historically has correlated with the market price of nitrogen
fertilizer products;
|
|
|
|
the cyclical nature of the nitrogen fertilizer business;
|
|
|
|
the dependence of the nitrogen fertilizer operations on a few
third-party suppliers;
|
|
|
|
the hazardous nature of ammonia, potential liability for
accidents involving ammonia that cause severe damage to property
and/or
injury to the environment and human health and potential
increased costs relating to transport of ammonia;
|
25
|
|
|
|
|
the reliance of the nitrogen fertilizer business on third-party
providers of transportation services and equipment;
|
|
|
|
operating hazards and interruptions, including unscheduled
downtime and maintenance;
|
|
|
|
capital expenditures required by environmental laws and
regulations for the petroleum and nitrogen fertilizer businesses;
|
|
|
|
changes in our credit profile;
|
|
|
|
our significant indebtedness
|
|
|
|
severe weather conditions and natural disasters;
|
|
|
|
the supply and price levels of essential raw materials; and
|
|
|
|
the international credit crisis and global recession.
|
All forward-looking statements contained in this
Form 10-Q
speak only as of the date of this document. We undertake no
obligation to update or revise publicly any forward-looking
statements to reflect events or circumstances that occur after
the date of this
Form 10-Q,
or to reflect the occurrence of unanticipated events.
Company
Overview
CVR Energy, Inc. and, unless the context requires otherwise, its
subsidiaries (CVR, the Company,
we, us or our) is an
independent refiner and marketer of high value transportation
fuels. In addition, we currently own all of the interests (other
than the managing general partner interest (managing GP
interest) and associated incentive distribution rights
(the IDRs) in CVR Partners, LP (the
Partnership) a limited partnership which produces
the nitrogen fertilizers, ammonia and urea ammonium nitrate
(UAN).
Any references to the Company as of a date prior to
October 16, 2007 and subsequent to June 24, 2005 are
to Coffeyville Acquisition LLC (CALLC) and its
subsidiaries. CALLC formed CVR Energy, Inc. as a wholly owned
subsidiary, incorporated in Delaware in September 2006, in order
to effect an initial public offering. The initial public
offering of CVR was consummated on October 26, 2007. In
conjunction with the initial public offering, 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:
CALLC and Coffeyville Acquisition II LLC (CALLC
II).
We operate under two business segments: petroleum and nitrogen
fertilizer. Throughout the remainder of this document, our
business segments are referred to as our petroleum
business and our nitrogen fertilizer business,
respectively.
Petroleum business.
Our petroleum business
includes a 115,000 barrels per day (bpd)
complex full coking medium-sour crude refinery in Coffeyville,
Kansas. In addition to the refinery, we own and operate
supporting businesses that include (1) a crude oil
gathering system serving central Kansas, northern Oklahoma,
western Missouri, eastern Colorado and southwest Nebraska,
(2) storage and terminal facilities for asphalt and refined
fuels in Phillipsburg, Kansas, (3) a 145,000 bpd
pipeline system that transports crude oil to our refinery and
associated crude oil storage tanks with a capacity of
1.2 million barrels and (4) a rack marketing division
supplying product through tanker trucks directly to customers
located in close geographic proximity to Coffeyville and
Phillipsburg and to customers at throughput terminals on
Magellan Midstream Partners L.P.s (Magellan)
refined products distribution systems. Additionally, we lease
2.7 million barrels of storage capacity at Cushing,
Oklahoma. 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 the Magellan pipeline and into Colorado and other
destinations utilizing the product pipeline networks owned by
Magellan, Enterprise Products Operating, L.P. and NuStar Energy,
L.P. Our refinery is situated approximately 100 miles from
Cushing, Oklahoma, one of the largest crude oil trading and
storage hubs in the United States. Cushing is supplied by
numerous pipelines from locations including the U.S. Gulf
Coast and Canada, providing us with access to virtually any
crude oil variety in the world capable of being transported by
pipeline.
26
Crude oil is supplied to our refinery through our owned and
leased gathering system and by a Plains American L.P. pipeline
from Cushing, Oklahoma. We maintain capacity on the Spearhead
Pipeline from Canada and receive foreign and deepwater domestic
crude oils via the Seaway Pipeline system. We have also signed a
contract for additional pipeline capacity on the proposed
Keystone pipeline project currently under development. We also
maintain leased storage in Cushing to facilitate optimal crude
purchasing and blending. Our refinery blend consists of a
combination of crude oil grades, including onshore and offshore
domestic grades, various Canadian medium and heavy sours and
sweet synthetics and a variety of South American, North Sea,
Middle East and West African imported grades. The access to a
variety of crude oils coupled with the complexity of our
refinery allows us to purchase crude oil at a discount to West
Texas Intermediate, (WTI). Our crude consumed cost
discount to WTI for the first quarter of 2009 was $(6.47) per
barrel compared to $(5.31) per barrel in the first quarter of
2008.
Nitrogen fertilizer business.
The nitrogen
fertilizer business consists of a nitrogen fertilizer
manufacturing facility, comprised of (1) an 84 million
standard cubic foot per day gasifier complex, which consumes
approximately 1,500 tons per day of pet coke to produce
hydrogen, (2) a 1,225
ton-per-day
ammonia unit and (3) a 2,025
ton-per-day
UAN unit. In 2008, the nitrogen fertilizer business produced
approximately 359,120 tons of ammonia, of which approximately
69% was upgraded into approximately 599,172 tons of UAN.
The nitrogen fertilizer plant in Coffeyville, Kansas includes a
pet coke gasifier that produces high purity hydrogen which in
turn is converted to ammonia at a related ammonia synthesis
plant. Ammonia is further upgraded into UAN solution in a
related UAN unit. Pet coke is a low value by-product of the
refinery coking process. On average during the last five years,
more than 77% of the pet coke consumed by the nitrogen
fertilizer plant was produced by our refinery. The nitrogen
fertilizer business obtains most of its pet coke via a long-term
coke supply agreement with our refinery.
The nitrogen fertilizer plant is the only operation in North
America utilizing a pet coke gasification process to produce
nitrogen fertilizers (based on data provided by Blue
Johnson & Associates). Its redundant train gasifier
provides good on-stream reliability and the use of low cost
by-product pet coke feed (rather than natural gas) to produce
hydrogen provides the facility with a significant competitive
advantage during periods of high natural gas prices. Fertilizer
prices generally increase with natural gas prices, without a
directly related change in cost (because pet coke is used as a
primary raw material rather than natural gas). The nitrogen
fertilizer business competition utilizes natural gas to
produce ammonia.
With the recent downturn in the economy, natural gas consumption
has declined, resulting in a significant decrease in natural gas
prices in recent months. Prices dipped below $4 per MMBtu as of
March 31, 2009. The recent decline in natural gas prices
has enabled natural gas based producers to manufacture at lower
costs; which may impact prices of nitrogen fertilizer.
General Overview.
Due to the weakness of the
general economy, including the tightness in the credit markets,
and short-term tightening in demand of the petroleum and
nitrogen fertilizer products, both the petroleum business and
nitrogen fertilizer business are focused on enhancing
operational efficiency, controlling operational expenditures and
minimizing capital spending. Inventory management practices are
being employed to respond to the changes in demand levels which
impact our production volumes in both businesses.
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,
27
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 changes in the value of our 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,
domestic and international political and economic developments
and other factors beyond our control are likely to continue to
play an important role in refining industry economics. These
factors can impact, among other things, the level of inventories
in the market, resulting in price volatility and a reduction in
product margins. Moreover, the refining industry typically
experiences seasonal fluctuations in demand for refined
products, such as increases in the demand for gasoline during
the summer driving season and for home heating oil during the
winter, primarily in the Northeast.
In order to assess our operating performance, we compare our net
sales, less cost of product sold, or our refining margin,
against a widely used 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, we refer to the benchmark as the NYMEX 2-1-1 crack spread,
or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is
expressed in dollars per barrel and is a proxy for the per
barrel margin that a sweet crude refinery would earn assuming it
produced and sold the benchmark production of gasoline and
distillate.
Although the 2-1-1 crack spread is a benchmark for our refinery
margin, because our refinery has certain feedstock costs and
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
our 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. We measure
the cost advantage of our crude oil slate by calculating the
spread between the price of our delivered crude oil and the
price of WTI. The spread is referred to as our consumed crude
differential. Our refinery margin can be impacted significantly
by the consumed crude differential. Our consumed crude
differential will move directionally with changes in the West
Texas Sour crude oil (WTS) differential to WTI and
the West Canadian Select (WCS) 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 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. The WTI less WCS
differential was $3.26 and $19.84 per barrel, for the three
months ended March 31, 2009 and 2008, respectively. The WTI
less WTS differential was $1.04 and $4.63 per barrel for the
three months ended March 31, 2009 and 2008, respectively.
While there was contraction in the sweet-sour and heavy-sour
crude oil markets during the first quarter of 2009, the impact
of this contraction on our crude differential was offset in part
due to the ongoing contango in the WTI crude oil market.
Contango markets are characterized by prices for future delivery
that are higher than the current or spot price of the commodity.
Our quarterly crude costs benefited in the first quarter of 2009
from the ongoing contango. Our consumed crude less WTI
differential was $(6.47) and $(5.31) per barrel for the three
months ended March 31, 2009 and 2008, respectively.
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 in our region include the logistics
cost for U.S. Gulf Coast refineries to ship into our
region. The result of this logistical advantage and the fact
that the actual product specifications used to determine the
NYMEX are different from the actual production in our 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
28
PADD II, Group 3 vs. NYMEX basis, or heating oil basis. If
gasoline and heating oil basis are greater than zero, this would
mean that prices in our marketing area exceed those used in the
2-1-1 crack spread. Heating oil basis for the first quarter 2009
and 2008 was $(1.82) and $3.65 per barrel, respectively.
Gasoline basis for the first quarter 2009 was $(0.64) per
barrel, compared to $(1.46) per barrel in the first quarter of
2008.
Our direct operating expense structure is also important to our
profitability. Major direct operating expenses include energy,
employee labor, maintenance, contract labor, and environmental
compliance. Our predominant variable cost is energy which is
comprised primarily of electrical cost and natural gas. We are
therefore sensitive to the movements of natural gas prices.
Consistent, safe, and reliable operations at our refinery are
key to our financial performance and results of operations.
Unplanned downtime at our refinery may result in lost margin
opportunity, increased maintenance expense, a temporary increase
in working capital investment and related inventory position. We
seek to mitigate the financial impact of planned downtime, such
as major turnaround maintenance, through a diligent planning
process that takes into account the margin environment, the
availability of resources to perform the needed maintenance,
feedstock logistics and other factors. The refinery generally
undergoes a facility turnaround every four to five years. The
length of the turnaround is contingent upon the scope of work to
be completed. The last refinery turnaround was completed in
April 2007, and the next refinery turnaround is scheduled for
the fourth quarter of 2011.
Because petroleum feedstocks and products are essentially
commodities, we have no control over the changing market.
Therefore, the lower target inventory we are able to maintain
significantly reduces the impact of commodity price volatility
on our petroleum product inventory position relative to other
refiners. This target inventory position is generally not
hedged. To the extent our inventory position deviates from the
target level, we consider risk mitigation activities usually
through the purchase or sale of futures contracts on the NYMEX.
Our hedging activities carry customary time, location and
product grade basis risks generally associated with hedging
activities. Because most of our titled inventory is valued under
the FIFO costing method, price fluctuations on our target level
of titled inventory have a major effect on our financial results
unless the market value of our target inventory is increased
above cost.
As the petroleum business has continued to increase its product
output and, for the first quarter 2009, has experienced record
levels of outbound shipments, product shipping logistics are
beginning to surface as a potential limitation. We are
continuing to evaluate and look at alternatives for shipping
refined products out of the refinery. We do not expect any
outbound transportation constraints to have a material or
significant impact to the results of the operations of the
petroleum business.
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 and, as a result, is not
directly impacted in terms of cost, by high or volatile swings
in natural gas prices. Instead, our adjacent oil refinery
supplies most of the pet coke feedstock needed by the nitrogen
fertilizer business pursuant to a long-term coke supply
agreement we entered into in October 2007. The price at which
nitrogen fertilizer products are ultimately sold depends on
numerous factors, including the supply of, and the demand for,
nitrogen fertilizer products which, in turn, depends on, among
other factors, the price of natural gas, the cost and
availability of fertilizer transportation infrastructure,
changes in the world population, weather conditions, grain
production levels, the availability of imports, and the extent
of government intervention in agriculture markets. While net
sales of the nitrogen fertilizer business could fluctuate
significantly with movements in natural gas prices during
periods when fertilizer markets are weak and nitrogen fertilizer
products sell at low prices, high natural gas prices do not
force the nitrogen fertilizer business to shut down its
operations as is the case with our competitors who rely heavily
on natural gas instead of pet coke as a primary feedstock.
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
29
volatility, domestic and 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 nitrogen fertilizers is affected by the aggregate
crop planting decisions and nitrogen 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 nitrogen fertilizer they apply depend on factors such
as crop prices, their current liquidity, soil conditions,
weather patterns and the types of crops planted.
The United States Department of Agriculture reported on
March 31, 2009 that growers plan to plant 85 million
acres of corn in 2009. While this number is down from the prior
two periods, it is the third largest acreage since 1949. Due to
the growing global population, expectations remain for future
increased demand in spite of the global economic downturn.
The nitrogen fertilizer spring application period was negatively
impacted by the limited planting caused by late winter storms
and recent persistent wet weather in the mid-continent. This
delay will result in a shortened but potentially more intense
application period as weather permits.
We anticipate that second quarter plant gate prices will
continue to be above current prices due to the impact of our
order book. Over time, prices should trend downward toward spot
prices; however, at this time with the current delay of the
planting season, we cannot estimate the full impact.
In order to assess the operating performance of the nitrogen
fertilizer business, we calculate plant gate price to determine
our operating margin. Plant gate price refers to the unit price
of fertilizer, in dollars per ton, offered on a delivered basis,
excluding shipment costs. Instead of experiencing high
variability in the cost of raw materials, the nitrogen
fertilizer business utilizes less than 1% of the natural gas
used by natural gas-based fertilizer producers.
Because the nitrogen fertilizer plant has certain logistical
advantages relative to end users of ammonia and UAN and demand
relative to our production has remained high, the nitrogen
fertilizer business primarily targets end users in the
U.S. farm belt where it incurs lower freight costs as
compared to competitors. The nitrogen fertilizer business does
not incur any barge or pipeline freight charges when it sells in
these markets, giving us a distribution cost advantage over
U.S. Gulf Coast importers. Selling products to customers
within economic rail transportation limits of the nitrogen
fertilizer plant and keeping transportation costs low are keys
to maintaining profitability.
The value of nitrogen fertilizer products is also an important
consideration in understanding our results. During 2008, the
nitrogen fertilizer business upgraded approximately 69% 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.
The direct operating expense structure of the nitrogen
fertilizer business also directly affects its profitability.
Using a pet coke gasification process, the nitrogen fertilizer
business has significantly higher fixed costs than natural
gas-based fertilizer plants. Major fixed operating expenses
include electrical energy, employee labor, maintenance,
including contract labor, and outside services. These costs
comprise the fixed costs associated with the nitrogen fertilizer
plant.
The nitrogen fertilizer business largest raw material
expense is pet coke, which it purchases from our refinery and
third parties. In 2008, the nitrogen fertilizer business spent
$14.1 million for pet coke. If pet coke prices rise
substantially in the future, the nitrogen fertilizer business
may be unable to increase its prices to recover increased raw
material costs, because market prices for nitrogen fertilizer
products are generally correlated with natural gas prices, the
primary raw material used by its competitors, and not pet coke
prices.
Consistent, safe, and reliable operations at the nitrogen
fertilizer plant are critical to its financial performance and
results of operations. Unplanned downtime of the nitrogen
fertilizer plant may result in lost
30
margin opportunity, increased maintenance expense, a temporary
increase in working capital investment and related inventory
position. The financial impact of planned downtime, such as
major turnaround maintenance, is mitigated through a diligent
planning process that takes into account margin environment, the
availability of resources to perform the needed maintenance,
feedstock logistics and other factors.
The nitrogen fertilizer business generally undergoes a facility
turnaround every two years. The turnaround typically lasts
15-20 days
each turnaround year and costs approximately $3-5 million
per turnaround. The facility underwent a turnaround in the
fourth quarter of 2008, and the next facility turnaround is
currently scheduled for the fourth quarter of 2010.
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.
Cash Flow
Swap
On June 16, 2005, CALLC entered into commodity derivative
contracts (referred to as the Cash Flow Swap) with
J. Aron & Company (J. Aron), a subsidiary
of The Goldman Sachs Group, Inc. and a related party of ours.
The Cash Flow Swap was subsequently assigned from CALLC to
Coffeyville Resources, LLC (CRLLC), a wholly-owned
subsidiary of CVR on June 24, 2005. The derivative took the
form of three NYMEX swap agreements whereby if absolute (i.e.,
in dollar terms, not a percentage of crude oil prices) crack
spreads fall below the fixed level, J. Aron agreed to pay the
difference to us, and if absolute crack spreads rise above the
fixed level, we agreed to pay the difference to J. Aron. Based
upon expected crude oil capacity of 115,000 bpd, the Cash
Flow Swap represents approximately 57% and 14% of crude oil
capacity for the periods January 1, 2009 through
June 30, 2009 and July 1, 2009 through June 30,
2010, respectively. 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
. As a result, the Statement of
Operations reflects all the realized and unrealized gains and
losses from this swap which can create significant changes
between periods.
For the three months ended March 31, 2009 and 2008, we
recorded net realized losses of $15.7 million and
$21.5 million, respectively, related to the Cash Flow Swap.
For the three months ended March 31, 2009 and 2008, we
recorded net unrealized losses of $20.1 million and
$13.9 million, respectively, related to the Cash Flow Swap.
Share-Based
Compensation
Through a wholly-owned subsidiary, we have two Phantom Unit
Appreciation Plans (the Phantom Unit Plans) whereby
directors, employees, and service providers may be awarded
phantom points at the discretion of the board of directors or
the compensation committee. We account for awards under our
Phantom Unit Plans as liability based awards. In accordance with
FAS 123(R), the expense associated with these awards for
2009 is based on the current fair value of the awards which was
derived from a probability-weighted expected return method. The
probability weighted expected return method involves a
forward-looking analysis of possible future outcomes, the
estimation of ranges of future and present value under each
outcome, and the application of a probability factor to each
outcome in conjunction with the application of the current value
of our common stock price with a Black-Scholes option pricing
formula, as remeasured at each reporting date until the awards
are settled.
Also, in conjunction with the initial public offering in October
2007, the override units of CALLC were modified and split evenly
into override units of CALLC and CALLC II. As a result of the
modification, the awards were no longer accounted for as
employee awards and became subject to the accounting guidance in
EITF Issue
No. 00-12,
Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee
and EITF
Issue
No. 96-18,
Accounting for Equity Investments that Are Issued to Other
than Employees for Acquiring or in Conjunction with Selling
Goods or Services
. In accordance with that
31
accounting guidance, the expense associated with the awards is
based on the current fair value of the awards which is derived
under the same methodology as the Phantom Unit Plans, as
remeasured at each reporting date until the awards vest. For the
three months ended March 31, 2009 and 2008, we increased
(reversed) compensation expense by $3.8 million and
$(0.5) million, respectively, as a result of the phantom
and override unit share-based compensation awards.
Results
of Operations
The following tables summarize the financial data and key
operating statistics for CVR and our two operating segments for
the three months ended March 31, 2009 and 2008. The summary
financial data for our two operating segments does not include
certain selling, general and administrative 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, 2008,
is unaudited.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions, except share data)
|
|
|
Consolidated Statement of Operations Data
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
609.4
|
|
|
$
|
1,223.0
|
|
Cost of product sold(1)
|
|
|
421.6
|
|
|
|
1,036.2
|
|
Direct operating expenses(1)
|
|
|
56.2
|
|
|
|
60.6
|
|
Selling, general and administrative expenses(1)
|
|
|
19.5
|
|
|
|
13.4
|
|
Net costs associated with flood(2)
|
|
|
0.2
|
|
|
|
5.8
|
|
Depreciation and amortization(3)
|
|
|
20.9
|
|
|
|
19.6
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
91.0
|
|
|
$
|
87.4
|
|
Other income, net
|
|
|
0.1
|
|
|
|
0.9
|
|
Interest expense and other financing costs
|
|
|
(11.5
|
)
|
|
|
(11.3
|
)
|
Gain (loss) on derivatives, net
|
|
|
(36.9
|
)
|
|
|
(47.9
|
)
|
|
|
|
|
|
|
|
|
|
Income before income tax expense
|
|
$
|
42.7
|
|
|
$
|
29.1
|
|
Income tax expense
|
|
|
12.0
|
|
|
|
6.9
|
|
|
|
|
|
|
|
|
|
|
Net income(4)
|
|
$
|
30.7
|
|
|
$
|
22.2
|
|
Basic earnings per share
|
|
$
|
0.36
|
|
|
$
|
0.26
|
|
Diluted earnings per share
|
|
$
|
0.36
|
|
|
$
|
0.26
|
|
Weighted average common shares outstanding:
|
|
|
|
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|
|
|
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Basic
|
|
|
86,243,745
|
|
|
|
86,141,291
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|
Diluted
|
|
|
86,322,411
|
|
|
|
86,158,791
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31,
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|
|
As of December 31,
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|
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2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
|
|
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(in millions)
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|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
28.4
|
|
|
$
|
8.9
|
|
Working capital
|
|
|
174.9
|
|
|
|
128.5
|
|
Total assets
|
|
|
1,575.8
|
|
|
|
1,610.5
|
|
Total debt, including current portion
|
|
|
490.9
|
|
|
|
495.9
|
|
Total CVR stockholders equity
|
|
|
612.1
|
|
|
|
579.5
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Cash Flow Data
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
36.7
|
|
|
|
24.2
|
|
Investing activities
|
|
|
(15.9
|
)
|
|
|
(26.2
|
)
|
Financing activities
|
|
|
(1.3
|
)
|
|
|
(3.4
|
)
|
Other Financial Data
|
|
|
|
|
|
|
|
|
Capital expenditures for property, plant and equipment
|
|
$
|
15.9
|
|
|
$
|
26.2
|
|
Depreciation and amortization
|
|
|
20.9
|
|
|
|
19.6
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap(5)
|
|
|
42.8
|
|
|
|
30.6
|
|
|
|
|
(1)
|
|
Amounts are shown exclusive of depreciation and amortization.
|
|
(2)
|
|
Represents the approximate net costs associated with the
June/July 2007 flood and crude oil spill that are not probable
of recovery.
|
|
(3)
|
|
Depreciation and amortization is comprised of the following
components as excluded from cost of product sold, direct
operating expenses and selling, general administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Depreciation and amortization excluded from cost of product sold
|
|
$
|
0.7
|
|
|
$
|
0.6
|
|
Depreciation and amortization excluded from direct operating
expenses
|
|
|
19.7
|
|
|
|
18.7
|
|
Depreciation and amortization excluded from selling, general and
administrative expenses
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
20.9
|
|
|
$
|
19.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4)
|
|
The following are certain charges and costs incurred in each of
the relevant periods that are meaningful to understanding our
net income and in evaluating our performance:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Funded letter of credit expense and interest rate swap not
included in interest expense(a)
|
|
$
|
4.3
|
|
|
$
|
0.9
|
|
Unrealized net (gain) loss from Cash Flow Swap
|
|
|
20.1
|
|
|
|
13.9
|
|
Share-based compensation expense(b)
|
|
|
3.9
|
|
|
|
(0.4
|
)
|
|
|
|
(a)
|
|
Consists of fees which are expensed to selling, general and
administrative expenses in connection with the funded letter of
credit facility of $150.0 million issued in support of the
Cash Flow Swap. We consider these fees to be equivalent to
interest expense and the fees are treated as such in the
calculation of consolidated adjusted EBITDA in the credit
facility.
|
|
(b)
|
|
Represents the impact of share-based compensation awards.
|
|
|
|
(5)
|
|
Net income (loss) 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,
|
33
|
|
|
|
|
LLC by CALLC on June 24, 2005. On June 16, 2005, CALLC
entered into the Cash Flow Swap with J. Aron. The Cash Flow Swap
was subsequently assigned from CALLC to CRLLC on June 24,
2005. The derivative took the form of three NYMEX swap
agreements whereby if absolute (i.e., in dollar terms, not a
percentage of crude oil prices) crack spreads fall below the
fixed level, J. Aron agreed to pay the difference to us, and if
absolute crack spreads rise above the fixed level, we agreed to
pay the difference to J. Aron. Based upon expected crude oil
capacity of 115,000 bpd, the Cash Flow Swap represents
approximately 57% and 14% of crude oil capacity for the periods
January 1, 2009 through June 30, 2009 and July 1,
2009 through June 30, 2010, respectively.
|
|
|
|
We have determined that the Cash Flow Swap does not qualify as a
hedge for hedge accounting purposes under current GAAP. As a
result, our periodic Statements of Operations reflect in each
period material amounts of unrealized gains and losses based on
the increases or decreases in market value of the unsettled
position under the swap agreements which are accounted for as an
asset or liability on our balance sheet, as applicable. As the
absolute crack spreads increase, we are required to record an
increase in this liability account with a corresponding expense
entry to be made to our Statements of Operations. Conversely, as
absolute crack spreads decline, we are required to record a
decrease in the swap related liability and post a corresponding
income entry to our Statement of Operations. Because of this
inverse relationship between the economic outlook for our
underlying business (as represented by crack spread levels) and
the income impact of the unrealized gains and losses, and given
the significant periodic fluctuations in the amounts of
unrealized gains and losses, management utilizes Net income
(loss) adjusted for unrealized gain or loss from Cash Flow Swap
as a key indicator of our business performance. In managing our
business and assessing its growth and profitability from a
strategic and financial planning perspective, management and our
board of directors considers our GAAP net income results as well
as Net income (loss) adjusted for unrealized gain or loss from
Cash Flow Swap. We believe that Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap enhances the
understanding of our results of operations by highlighting
income attributable to our ongoing operating performance
exclusive of charges and income resulting from mark-to-market
adjustments that are not necessarily indicative of the
performance of our underlying business and our industry. The
adjustment has been made for the unrealized gain or loss from
Cash Flow Swap net of its related tax effect.
|
|
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash
Flow Swap is not a recognized financial measure under GAAP and
should not be substituted for net income as a measure of our
performance but instead should be utilized as a supplemental
measure of financial performance or liquidity in evaluating our
business. Because Net income (loss) adjusted for unrealized gain
or loss from Cash Flow Swap excludes mark-to-market adjustments,
the measure does not reflect the fair market value of our Cash
Flow Swap in our net income. As a result, the measure does not
include potential cash payments that may be required to be made
on the Cash Flow Swap in the future. Also, our presentation of
this non-GAAP measure may not be comparable to similarly titled
measures of other companies.
|
The following is a reconciliation of Net income adjusted for
unrealized gain or loss from Cash Flow Swap to net income (in
millions):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
Net income adjusted for unrealized gain or loss from Cash Flow
Swap
|
|
$
|
42.8
|
|
|
$
|
30.6
|
|
Plus:
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from Cash Flow Swap, net of taxes
|
|
|
(12.1
|
)
|
|
|
(8.4
|
)
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
30.7
|
|
|
$
|
22.2
|
|
34
Petroleum
Business Results of Operations
The following tables below provide an overview of the petroleum
business results of operations, relevant market indicators
and its key operating statistics:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions, except operating statistics)
|
|
|
Petroleum Business Financial Results
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
545.3
|
|
|
$
|
1,168.5
|
|
Cost of product sold(1)
|
|
|
417.6
|
|
|
|
1,035.1
|
|
Direct operating expenses(1)(3)
|
|
|
34.6
|
|
|
|
40.3
|
|
Net costs associated with flood
|
|
|
0.2
|
|
|
|
5.5
|
|
Depreciation and amortization
|
|
|
15.9
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
Gross profit(3)
|
|
$
|
77.0
|
|
|
$
|
72.7
|
|
Plus direct operating expenses(1)
|
|
|
34.6
|
|
|
|
40.3
|
|
Plus net costs associated with flood
|
|
|
0.2
|
|
|
|
5.5
|
|
Plus depreciation and amortization
|
|
|
15.9
|
|
|
|
14.9
|
|
|
|
|
|
|
|
|
|
|
Refining margin(2)
|
|
|
127.7
|
|
|
|
133.4
|
|
Operating income
|
|
|
64.7
|
|
|
|
63.6
|
|
Key Operating Statistics
(per crude oil throughput barrel)
|
|
|
|
|
|
|
|
|
Refining margin(2)(3)
|
|
$
|
13.36
|
|
|
$
|
13.77
|
|
Gross profit(3)
|
|
$
|
8.06
|
|
|
$
|
7.51
|
|
Direct operating expenses(1)(3)
|
|
$
|
3.62
|
|
|
$
|
4.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
Refining Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet
|
|
|
74,958
|
|
|
|
62.1
|
|
|
|
73,043
|
|
|
|
61.0
|
|
Light/medium sour
|
|
|
20,733
|
|
|
|
17.2
|
|
|
|
18,079
|
|
|
|
15.1
|
|
Heavy sour
|
|
|
10,478
|
|
|
|
8.7
|
|
|
|
15,323
|
|
|
|
12.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil throughput
|
|
|
106,169
|
|
|
|
88.0
|
|
|
|
106,445
|
|
|
|
88.9
|
|
All other feedstocks and blendstocks
|
|
|
14,498
|
|
|
|
12.0
|
|
|
|
13,282
|
|
|
|
11.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
120,667
|
|
|
|
100.0
|
|
|
|
119,727
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
64,327
|
|
|
|
53.3
|
|
|
|
59,662
|
|
|
|
49.4
|
|
Distillate
|
|
|
46,184
|
|
|
|
38.3
|
|
|
|
48,591
|
|
|
|
40.3
|
|
Other (excluding internally produced fuel)
|
|
|
10,133
|
|
|
|
8.4
|
|
|
|
12,467
|
|
|
|
10.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refining production (excluding internally produced fuel)
|
|
|
120,644
|
|
|
|
100.0
|
|
|
|
120,720
|
|
|
|
100.0
|
|
Product price (dollars per gallon):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
|
|
|
$
|
1.24
|
|
|
|
|
|
|
$
|
2.45
|
|
Distillate
|
|
|
|
|
|
$
|
1.32
|
|
|
|
|
|
|
$
|
2.85
|
|
35
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Market Indicators (dollars per barrel)
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) NYMEX
|
|
$
|
43.31
|
|
|
$
|
97.82
|
|
Crude Oil Differentials:
|
|
|
|
|
|
|
|
|
WTI less WTS (light/medium sour)
|
|
|
1.04
|
|
|
|
4.63
|
|
WTI less WCS (heavy sour)
|
|
|
3.26
|
|
|
|
19.84
|
|
NYMEX Crack Spreads:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
9.07
|
|
|
|
6.46
|
|
Heating Oil
|
|
|
13.13
|
|
|
|
17.16
|
|
NYMEX 2-1-1 Crack Spread
|
|
|
11.10
|
|
|
|
11.81
|
|
PADD II Group 3 Basis:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
(0.64
|
)
|
|
|
(1.46
|
)
|
Ultra Low Sulfur Diesel
|
|
|
(1.82
|
)
|
|
|
3.65
|
|
PADD II Group 3 Product Crack:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
8.43
|
|
|
|
5.00
|
|
Ultra Low Sulfur Diesel
|
|
|
11.31
|
|
|
|
20.81
|
|
PADD II Group 3 2-1-1
|
|
|
9.87
|
|
|
|
12.90
|
|
|
|
|
(1)
|
|
Amounts are shown exclusive of depreciation and amortization.
|
|
(2)
|
|
Refining margin is a measurement calculated as the difference
between net sales and cost of product sold (exclusive of
depreciation and amortization). Refining margin is a non-GAAP
measure that we believe is important to investors in evaluating
our refinerys performance as a general indication of the
amount above our cost of product sold that we are able to sell
refined products. Each of the components used in this
calculation (net sales and cost of product sold (exclusive of
depreciation and amortization)) is taken directly from our
Statement of Operations. Our calculation of refining margin may
differ from similar calculations of other companies in our
industry, thereby limiting its usefulness as a comparative
measure. In order to derive the refining margin per crude oil
throughput barrel, we utilize the total dollar figures for
refining margin as derived above and divide by the applicable
number of crude oil throughput barrels for the period.
|
|
(3)
|
|
In order to derive the refining margin, direct operating expense
and gross profit in each case per crude oil throughput barrel,
we utilize the total dollar figures for refining margin as
derived above and divide by the applicable number of crude oil
throughput barrels for the period.
|
36
Nitrogen
Fertilizer Business Results of Operations
The tables below provide an overview of the nitrogen fertilizer
business results of operations, relevant market indicators
and key operating statistics:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Nitrogen Fertilizer Business Financial Results
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
67.8
|
|
|
$
|
62.6
|
|
Cost of product sold(1)
|
|
|
8.7
|
|
|
|
8.9
|
|
Direct operating expenses(1)
|
|
|
21.6
|
|
|
|
20.3
|
|
Depreciation and amortization
|
|
|
4.6
|
|
|
|
4.5
|
|
Operating income
|
|
$
|
29.3
|
|
|
$
|
26.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
Production (thousand tons):
|
|
|
|
|
|
|
|
|
Ammonia (gross produced)(2)
|
|
|
108.0
|
|
|
|
83.7
|
|
Ammonia (net available for sale)(2)
|
|
|
38.8
|
|
|
|
22.1
|
|
UAN
|
|
|
169.7
|
|
|
|
150.1
|
|
Petroleum coke consumed (thousand tons)
|
|
|
125.3
|
|
|
|
118.1
|
|
Petroleum coke (cost per ton)
|
|
$
|
35
|
|
|
$
|
30
|
|
Sales (thousand tons)(3):
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
48.0
|
|
|
|
24.1
|
|
UAN
|
|
|
143.0
|
|
|
|
158.0
|
|
|
|
|
|
|
|
|
|
|
Total sales
|
|
|
191.0
|
|
|
|
182.1
|
|
Product pricing (plant gate) (dollars per ton)(3):
|
|
|
|
|
|
|
|
|
Ammonia
|
|
$
|
373
|
|
|
$
|
494
|
|
UAN
|
|
$
|
316
|
|
|
$
|
262
|
|
On-stream factor(4):
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
100.0
|
%
|
|
|
91.8
|
%
|
Ammonia
|
|
|
100.0
|
%
|
|
|
90.7
|
%
|
UAN
|
|
|
96.0
|
%
|
|
|
85.9
|
%
|
Reconciliation to net sales (dollars in thousands):
|
|
|
|
|
|
|
|
|
Freight in revenue
|
|
$
|
4,121
|
|
|
$
|
4,022
|
|
Hydrogen revenue
|
|
|
658
|
|
|
|
5,291
|
|
Sales net plant gate
|
|
|
63,010
|
|
|
|
53,287
|
|
|
|
|
|
|
|
|
|
|
Total net sales
|
|
$
|
67,789
|
|
|
$
|
62,600
|
|
37
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
Market Indicators
|
|
|
|
|
|
|
|
|
Natural gas NYMEX (dollars per MMBtu)
|
|
$
|
4.47
|
|
|
$
|
8.74
|
|
Ammonia Southern Plains (dollars per ton)
|
|
$
|
337
|
|
|
$
|
590
|
|
UAN Mid Cornbelt (dollars per ton)
|
|
$
|
274
|
|
|
$
|
371
|
|
|
|
|
(1)
|
|
Amounts are shown exclusive of depreciation and amortization.
|
|
(2)
|
|
The gross tons produced for ammonia represent the total ammonia
produced, including ammonia produced that was upgraded into UAN.
The net tons available for sale represent the ammonia available
for sale that was not upgraded into UAN.
|
|
(3)
|
|
Plant gate sales per ton represent net sales less freight and
hydrogen revenue divided by product sales volume in tons in the
reporting period. Plant gate pricing per ton is shown in order
to provide a pricing measure that is comparable across the
fertilizer industry.
|
|
(4)
|
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On-stream factor is the total number of hours operated divided
by the total number of hours in the reporting period.
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Three
Months Ended March 31, 2009 Compared to the Three Months
Ended March 31, 2008
Consolidated
Results of Operations
Net Sales.
Consolidated net sales were
$609.4 million for the three months ended March 31,
2009 compared to $1,223.0 million for the three months
ended March 31, 2008. The decrease of $613.6 million
for the three months ended March 31, 2009 as compared to
the three months ended March 31, 2008 was primarily due to
a decrease in petroleum net sales of $623.2 million that
resulted from lower product prices ($598.2 million) and
lower sales volumes ($25.0 million). Nitrogen fertilizer
net sales increased $5.2 million for the three months ended
March 31, 2009 as compared to the three months ended
March 31, 2008 primarily due to higher plant gate prices
($3.0 million) and higher overall sales volume
($2.2 million).
Cost of Product Sold (Exclusive of Depreciation and
Amortization).
Consolidated cost of product
sold (exclusive of depreciation and amortization) was
$421.6 million for the three months ended March 31,
2009 as compared to $1,036.2 million for the three months
ended March 31, 2008. The decrease of $614.6 million
for the three months ended March 31, 2009 as compared to
the three months ended March 31, 2008 primarily resulted
from a significant decrease in raw material cost, primarily
crude oil.
Direct Operating Expenses (Exclusive of Depreciation and
Amortization).
Consolidated direct operating
expenses (exclusive of depreciation and amortization) were
$56.2 million for the three months ended March 31,
2009 as compared to $60.6 million for the three months
ended March 31, 2008. This decrease of $4.4 million
for the three months ended March 31, 2009 as compared to
the three months ended March 31, 2008 was due to a decrease
in petroleum direct operating expenses of $5.7 million,
primarily related to decreases in expenses associated with
utilities and energy, repairs and maintenance, property taxes,
outside services, operating materials and environmental,
partially offset by increases in expenses associated with labor,
insurance, rent and chemicals. Nitrogen fertilizer direct
operating expenses increased during the comparable period by
$1.3 million, primarily due to increases in expenses
associated with utilities, labor, property taxes, catalyst and
outside services, partially offset by decreases in expenses
associated with repairs and maintenance.
Selling, General and Administrative Expenses (Exclusive of
Depreciation and Amortization).
Consolidated
selling, general and administrative expenses (exclusive of
depreciation and amortization) were $19.5 million for the
three months ended March 31, 2009 as compared to $13.4
million for the three months ended March 31, 2008. This
variance was primarily the result of a decrease in expenses
associated with outside
38
services ($0.8 million) which was more than offset by
increases in expenses related to share-based compensation
($3.5 million), administrative payroll ($1.8 million),
and bank charges ($1.2 million).
Net Costs Associated with
Flood.
Consolidated net costs associated with
flood for the three months ended March 31, 2009
approximated $0.2 million as compared to $5.8 million
for the three months ended March 31, 2008.
Depreciation and
Amortization.
Consolidated depreciation and
amortization was $20.9 million for the three months ended
March 31, 2009 as compared to $19.6 million for the
three months ended March 31, 2008. The increase in
depreciation and amortization for the three months ended
March 31, 2009 as compared to the three months ended
March 31, 2008 was the result of additional capital
projects completed throughout 2008.
Operating Income.
Consolidated
operating income was $91.0 million for the three months
ended March 31, 2009 as compared to an operating income of
$87.4 million for the three months ended March 31,
2008. For the three months ended March 31, 2009 as compared
to the three months ended March 31, 2008, petroleum
operating income increased $1.1 million and nitrogen
fertilizer operating income increased by $3.4 million.
Interest Expense.
Consolidated interest
expense for the three months ended March 31, 2009 was
$11.5 million as compared to interest expense of
$11.3 million for the three months ended March 31,
2008. This 0.2 million increase for the three months ended
March 31, 2009 as compared to the three months ended
March 31, 2008 primarily resulted from an overall increase
in the borrowing rates as a result of the second amendment to
our credit facility completed on December 22, 2008. This
amendment resulted in an increase of interest rate margin, and
LIBOR and the base rate have been set at a minimum of 3.25% and
4.25%, respectively. The increase in interest expense as a
result of the amendments impact on interest rate margin and base
rates was partially offset by a decrease in average borrowings
outstanding during the comparable periods.
Interest Income.
Interest income was
nominal for the three months ended March 31, 2009 as
compared to $0.7 million for the three months ended
March 31, 2008.
Gain (loss) on Derivatives, net.
We
have determined that the Cash Flow Swap and our other derivative
instruments do not qualify as hedges for hedge accounting
purposes under SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities.
For the three
months ended March 31, 2009, we incurred $36.9 million
in losses on derivatives. This compares to a $47.9 million
net loss on derivatives for the three months ended
March 31, 2008. This decrease in loss on derivatives, net
for the three months ended March 31, 2009 as compared to
the three months ended March 31, 2008 was primarily
attributable to a decrease in realized and unrealized losses on
hedge derivatives, excluding the Cash Flow Swap, of
$11.4 million over the comparable period. With respect to
the Cash Flow Swap, realized losses for the three months ended
March 31, 2009 and the three months ended March 31,
2008 were $15.7 million and $21.5 million,
respectively. The decrease in realized losses over the
comparable periods was primarily the result of lower average
crack spreads for the three months ended March 31, 2009 as
compared to the three months ended March 31, 2008.
Unrealized losses represent the change in the
mark-to-market
value on the unrealized portion of the Cash Flow Swap based on
changes in the NYMEX crack spread that is the basis for the Cash
Flow Swap. Unrealized losses on our Cash Flow Swap for the three
months ended March 31, 2009 and the three months ended
March 31, 2008 were $20.1 million and
$13.9 million, respectively.
Provision for Income Taxes.
Income tax
expense for the three months ended March 31, 2009 was
$12.0 million, or 28.1% of income before income taxes, as
compared to income tax expense of $6.9 million, or 23.6% of
earnings before income taxes, for the three months ended
March 31, 2008. This increase in the effective income tax
rate is primarily related to a reduction of expected credits
generated as a result of the production of ultra low sulfur
diesel fuel and Kansas State incentives generated under the High
Performance Incentive Program.
Net Income.
For the three months ended
March 31, 2009, net income increased to $30.7 million
as compared to net income of $22.2 million for the three
months ended March 31, 2008. Net income increased
$8.5 million compared to the first quarter of 2008
primarily due to improved results in our petroleum and nitrogen
fertilizer businesses, a reduction in losses on derivatives and
a reduction of the net costs associated
39
with flood. These impacts were partially offset by increased
selling, general and administrative expenses and a higher
effective income tax rate.
Petroleum
Business Results of Operations
Net Sales.
Petroleum net sales were
$545.3 million for the three months ended March 31,
2009 compared to $1,168.5 million for the three months
ended March 31, 2008. The decrease of $623.2 million
during the three months ended March 31, 2009 as compared to
the three months ended March 31, 2008 was primarily the
result of significantly lower product prices
($598.2 million) and lower overall sales volumes
($25.0 million). Our average sales price per gallon for the
three months ended March 31, 2009 for gasoline of $1.24 and
distillate of $1.32 decreased by 49% and 54%, respectively, as
compared to the three months ended March 31, 2008.
Cost of Product Sold (Exclusive of Depreciation and
Amortization).
Cost of product sold
(exclusive of depreciation and amortization) 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 $417.6 million for the three months ended
March 31, 2009 compared to $1,035.1 million for the
three months ended March 31, 2008. The decrease of
$617.5 million during the three months ended March 31,
2009 as compared to the three months ended March 31, 2008
was primarily the result of a significant decrease in crude oil
prices and the impact of FIFO accounting also impacted cost of
product sold during the comparable periods. Our average cost per
barrel of crude oil consumed for the three months ended
March 31, 2009 was $36.75 compared to $92.35 for the
comparable period of 2008, a decrease of 60%. Sales volume of
refined fuels decreased 4% for the three months ended
March 31, 2009 as compared to the three months ended
March 31, 2008. In addition, under our FIFO accounting
method, changes in crude oil prices can cause fluctuations in
the inventory valuation of our crude oil, work in process and
finished goods, thereby resulting in a favorable FIFO inventory
impact when crude oil prices increase and an unfavorable FIFO
inventory impact when crude oil prices decrease. For the three
months ended March 31, 2009, we had an unfavorable FIFO
inventory impact of $6.0 million compared to a favorable
FIFO inventory impact of $20.0 million for the comparable
period of 2008.
Refining margin per barrel of crude throughput decreased from
$13.77 for the three months ended March 31, 2008 to $13.36
for the three months ended March 31, 2009. Gross profit per
barrel increased to $8.06 in the first quarter of 2009 as
compared to gross profit per barrel of $7.51 in the equivalent
period in 2008. The primary contributors to the slightly
negative variance in refining margin per barrel of crude
throughput were an increase in unfavorable FIFO impacts and
decreases in crude oil differentials over the comparable
periods. Decreased discounts for sour crude oils evidenced by
the $1.04 per barrel, or 78%, 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
three months ended March 31, 2009 as compared to the three
months ended March 31, 2008. In addition, a 6% decrease
($0.71 per barrel) in the average NYMEX 2-1-1 crack spread over
the comparable periods and negative regional differences between
distillate prices in our primary marketing region (the
Coffeyville supply area) and those of the NYMEX also negatively
impacted refining margin per barrel over the comparable periods.
The average distillate basis for the three months ended
March 31, 2009 decreased by $5.47 per barrel to $(1.82) per
barrel compared to $3.65 per barrel in the comparable period of
2008. Partially offsetting the negative effects of FIFO
inventory losses, crude oil differentials, the NYMEX 2-1-1 crack
spread and distillate basis was the steep crude oil discounts
achieved during the three month period ended March 31, 2009
as a result of a steep contango in the U.S. crude oil
market and improved basis between gasoline in the Coffeyville
supply area and the NYMEX. The average gasoline basis increased
by $0.82 per barrel to $(0.64) per barrel compared to $(1.46)
per barrel in the comparable period of 2008.
Direct Operating Expenses (Exclusive of Depreciation and
Amortization).
Direct operating expenses for
our petroleum operations include costs associated with the
actual operations of our refinery, such as energy and utility
costs, catalyst and chemical costs, repairs and maintenance,
labor and environmental compliance costs. Petroleum direct
operating expenses (exclusive of depreciation and amortization)
were $34.6 million for the three months ended
March 31, 2009 compared to direct operating expenses of
$40.3 million for the three months ended March 31,
2008.
40
The decrease of $5.7 million for the three months ended
March 31, 2009 compared to the three months ended
March 31, 2008 was the result of decreases in expenses
associated with utilities and energy ($3.0 million),
repairs and maintenance ($2.5 million), property taxes
($1.2 million), outside services ($1.2 million),
operating materials ($0.3 million) and environmental
($0.2 million). These decreases in direct operating
expenses were partially offset by increases in expenses
associated with labor ($1.6 million), insurance
($0.7 million), rent ($0.2 million) and chemicals
($0.2 million). On a per barrel of crude throughput basis,
direct operating expenses per barrel of crude oil throughput for
the three months ended March 31, 2009 decreased to $3.62
per barrel as compared to $4.16 per barrel for the three months
ended March 31, 2008.
Net Costs Associated with
Flood.
Petroleum net costs associated with
flood for the three months ended March 31, 2009
approximated $0.2 million compared to $5.5 million for
the three months ended March 31, 2008.
Depreciation and
Amortization.
Petroleum depreciation and
amortization was $15.9 million for the three months ended
March 31, 2009 as compared to $14.9 million for the
three months ended March 31, 2008. This increase in
petroleum depreciation and amortization for the three months
ended March 31, 2009 as compared to the three months ended
March 31, 2008 was primarily the result of the completion
of several large capital projects in recent prior periods.
Operating Income.
Petroleum operating
income was $64.7 million for the three months ended
March 31, 2009 as compared to $63.6 million for the
three months ended March 31, 2008. This increase of
$1.1 million from the three months ended March 31,
2009 as compared to the three months ended March 31, 2008
was primarily the result of improved gross profit per barrel and
decreases in expenses associated with utilities and energy
($3.0 million), repairs and maintenance
($2.5 million), property taxes ($1.2 million), outside
services ($1.2 million), operating materials
($0.3 million) and environmental ($0.2 million). These
decreases in direct operating expenses were partially offset by
increases in expenses associated with labor ($1.6 million),
insurance ($0.7 million), rent ($0.2 million) and
chemicals ($0.2 million).
Nitrogen
Fertilizer Business Results of Operations
Net Sales.
Nitrogen fertilizer net
sales were $67.8 million for the three months ended
March 31, 2009 compared to $62.6 million for the three
months ended March 31, 2008. The increase of
$5.2 million for the three months ended March 31, 2009
as compared to the three months ended March 31, 2008 was
the result of both higher average plant gate prices
($3.0 million) and higher product sales volume
($2.2 million).
In regard to product sales volumes for the three months ended
March 31, 2009, our nitrogen fertilizer operations
experienced an increase of 99% in ammonia sales unit volumes and
a decrease of 10% in UAN sales unit volumes. On-stream factors
(total number of hours operated divided by total hours in the
reporting period) for the gasification and the ammonia units
increased over the comparable periods with both units reporting
100% on-stream for the three months ended March 31, 2009.
The on-stream factor for the UAN plant was 96.0% for the three
months ended March 31, 2009, which was also greater than
the three months ended March 31, 2008. Although the
on-stream factors for the three months ending March 31,
2009 were outstanding, 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 March 31, 2009 for ammonia were
lower than the comparable period of 2008 by 25%. Plant gate
prices for the three months ended March 31, 2009 for UAN
were greater than plant gate prices for the comparable period of
2008 by 21%.
41
The demand for nitrogen fertilizer is affected by the aggregate
crop planting decisions and nitrogen 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 nitrogen fertilizer they apply depend on factors like
crop prices, their current liquidity, soil conditions, weather
patterns and the types of crops planted.
Cost of Product Sold (Exclusive of Depreciation and
Amortization).
Cost of product sold
(exclusive of depreciation and amortization) is primarily
comprised of pet coke expense and freight and distribution
expenses. Cost of product sold (excluding depreciation and
amortization) for the three months ended March 31, 2009 was
$8.7 million compared to $8.9 million for the three
months ended March 31, 2008. The decrease of
$0.2 million for the three months ended March 31, 2009
as compared to the three months ended March 31, 2008 was
primarily the result of an increase in expenses associated with
petroleum coke ($0.9 million), more than offset by
decreases in expenses associated with the change in inventory
($1.1 million) and distribution ($0.2 million).
Direct Operating Expenses (Exclusive of Depreciation and
Amortization).
Direct operating expenses for
our nitrogen fertilizer operations include costs associated with
the actual operations of our nitrogen plant, such as repairs and
maintenance, energy and utility costs, catalyst and chemical
costs, outside services, labor and environmental compliance
costs. Nitrogen direct operating expenses (exclusive of
depreciation and amortization) for the three months ended
March 31, 2009 were $21.6 million as compared to
$20.3 million for the three months ended March 31,
2008. The increase of $1.3 million for the three months
ended March 31, 2009 as compared to the three months ended
March 31, 2008 was primarily the result of increases in
expenses associated with utilities ($1.9 million), labor
($0.5 million), taxes ($0.5 million), catalyst
($0.3 million) and outside services ($0.2 million).
These increases in direct operating expenses were partially
offset by decreases in expenses associated with repairs and
maintenance ($2.5 million).
Depreciation and Amortization.
Nitrogen
fertilizer depreciation and amortization increased to
$4.6 million for the three months ended March 31, 2009
as compared to $4.5 million for the three months ended
March 31, 2008.
Operating Income.
Nitrogen fertilizer
operating income was $29.3 million for the three months
ended March 31, 2009 as compared to operating income of
$26.0 million for the three months ended March 31,
2008. This increase of $3.3 million for the three months
ended March 31, 2009 as compared to the three months ended
March 31, 2008 was primarily the result of increased
product sales volume and fertilizer prices over the comparable
periods. Additionally, decreased direct operating expenses
associated with repairs and maintenance ($2.5 million) also
contributed to the positive operating income comparison over the
comparable periods. These decreases in expenses were partially
offset by increased direct operating expenses primarily the
result of increases in expenses associated with utilities
($1.9 million), labor ($0.5 million), taxes
($0.5 million), catalyst ($0.3 million) and outside
services ($0.2 million).
Liquidity
and Capital Resources
Our primary sources of liquidity currently consist of cash
generated from our operating activities, existing cash and cash
equivalent balances and our existing revolving credit facility.
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 and nitrogen fertilizer products at margins sufficient
to cover fixed and variable expenses.
We believe that our cash flows from operations and existing cash
and cash equivalent balances, together with borrowings under our
existing revolving credit facility as necessary, 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.
42
Cash
Balance and Other Liquidity
As of March 31, 2009, we had cash and cash equivalents of
$28.4 million. As of March 31, 2009 and April 30,
2009, we had no amounts outstanding under our revolving credit
facility and aggregate availability of $116.1 million under
our revolving credit facility. At April 30, 2009, we had
cash and cash equivalents of $40.6 million.
At March 31, 2009, funded long-term debt, including current
maturities, totaled $483.1 million of tranche D term
loans. Other commitments at March 31, 2009 included a
$150.0 million funded letter of credit facility and a
$150.0 million revolving credit facility. As of
December 31, 2008, the commitment outstanding on the
revolving credit facility was $49.9 million, including
$0 million in borrowings, $3.3 million in letters of
credit in support of certain environmental obligations, and
$46.6 million in letters of credit to secure transportation
services for crude oil. As of April 30, 2009, total
outstanding debt under our credit facility was
$481.9 million, which was all term debt.
Working capital at March 31, 2009 was $174.9 million,
consisting of $354.8 million in current assets and
$179.9 million in current liabilities. Working capital at
December 31, 2008 was $128.5 million, consisting of
$373.4 million in current assets and $244.9 million in
current liabilities.
Credit
Facility
Our credit facility currently consists of tranche D term
loans with an outstanding balance of $483.1 million at
March 31, 2009, a $150.0 million revolving credit
facility, and a funded letter of credit facility of
$150.0 million issued in support of the Cash Flow Swap.
The $483.1 million of tranche D term loans outstanding
as of March 31, 2009 are subject to quarterly principal
amortization payments of 0.25% of the outstanding balance,
increasing to 23.5% of the outstanding principal balance on
April 1, 2013 and the next two quarters, with a final
payment of the aggregate outstanding balance on
December 28, 2013.
The revolving credit facility of $150.0 million provides
for direct cash borrowings for general corporate purposes and on
a short-term basis. Letters of credit issued under the revolving
loan facility are subject to a $75.0 million
sub-limit.
Outstanding letters of credit reduce the amount available under
our revolving credit facility. 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 March 31, 2009, we had available
$116.1 million under the revolving credit facility.
The $150.0 million funded letter of credit facility
provides credit support for our obligations under the Cash Flow
Swap. The funded letter of credit facility is fully cash
collateralized by the funding by the lenders of cash into a
credit linked deposit account. This account is held by the
funded letter of credit issuing bank. Contingent upon the
requirements of the Cash Flow Swap, the borrower has the ability
to reduce the funded letter of credit at any time upon written
notice to the lenders. The funded letter of credit facility
expires on December 28, 2010.
On December 22, 2008, CRLLC entered into a second amendment
to its credit facility. The amendment was entered into, among
other things, to amend the definition of consolidated adjusted
EBITDA to add a FIFO adjustment which applies for the year
ending December 31, 2008 through the quarter ending
September 30, 2009. This FIFO adjustment will be used for
the purpose of testing compliance with the financial covenants
under the credit facility until the quarter ending June 30,
2010. CRLLC sought and obtained the amendment due to the
dramatic decrease in the price of crude oil in the fourth
quarter of 2008 and the effect that such crude oil price
decrease would have had on the measurement of the financial
ratios under the credit facility. As part of the amendment,
CRLLCs interest rate margin increased by 2.50%, and LIBOR
and the base rate have been set at a minimum of 3.25% and 4.25%,
respectively.
43
After giving effect to the second amendment, 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 4.50%, or, at the borrowers
option, (b) LIBOR plus 5.50% (with step-downs to the prime
rate/federal funds rate plus 4.25% or 4.00% or LIBOR plus 5.25%
or 5.50%, respectively, upon achievement of certain rating
conditions).
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Revolving credit 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 4.50%, or, at the borrowers
option, (b) LIBOR plus 5.50% (with step-downs to the prime
rate/federal funds rate plus 4.25% or 4.00% or LIBOR plus 5.25%
or 5.00%, respectively, upon achievement of certain rating
conditions). Revolving credit lenders receive commitment fees
equal to the amount of undrawn revolving credit loans times 0.5%
per annum.
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Letters of credit issued under the $75.0 million
sub-limit
available under the revolving credit facility are subject to a
fee equal to the applicable margin on revolving LIBOR loans
owing to all revolving credit 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. CRLLC 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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The amendment provides for more restrictive requirements. Among
other things, CRLLC is subject to more stringent obligations
under certain circumstances to make mandatory prepayments of
loans. In addition, the amendment increased the percentage of
excess cash flow during any fiscal year that must be used to
prepay the loans and eliminated a basket which
previously allowed CRLLC to pay dividends of up to
$35.0 million per year.
The credit facility requires CRLLC to prepay outstanding loans,
subject to certain exceptions. Some of the requirements, among
other things, are as follows:
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100% of the asset sale proceeds must be used to repay
outstanding loans;
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100% of the cash proceeds from the incurrence of specified debt
obligations must be used to prepay outstanding loans; and
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100% of consolidated excess cash flow less 100% of voluntary
prepayments made during the fiscal year must be used to prepay
outstanding loans; provided that with respect to any fiscal year
commencing with fiscal 2008, this percentage will be reduced to
75% if the total leverage ratio at the end of such fiscal year
is less than 1.50:1.00 or 50% if the total leverage ratio as of
the end of such fiscal year is less than 1.00:1.00.
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Under the terms of our credit facility, the interest margin paid
is subject to change based on changes in our leverage ratio and
changes in our credit rating by either Standard &
Poors (S&P) or Moodys.
S&Ps announcement in February 2009 to place the
Company on negative outlook resulted in an increase in our
interest rate of 0.25% on amounts borrowed under our term loan
facility, revolving credit facility and the $150.0 million
funded letter of credit facility.
The credit facility contains customary covenants, which, among
other things, restrict, subject to certain exceptions, the
ability of CRLLC and its subsidiaries to incur additional
indebtedness, create liens on assets, make restricted junior
payments, enter into agreements that restrict subsidiary
distributions, make investments, loans or advances, engage in
mergers, acquisitions or sales of assets, dispose of subsidiary
interests, enter into sale and leaseback transactions, engage in
certain transactions with affiliates and stockholders, change
the business conducted by the credit parties, and enter into
hedging agreements. The credit facility provides that CRLLC may
not enter into commodity agreements if, after giving effect
thereto, the exposure under all such commodity agreements
exceeds 75% of Actual Production (the estimated future
production of refined products
44
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, CRLLC 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 requisite 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 CRLLC to maintain certain
financial ratios as follows:
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Minimum
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Maximum
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Interest
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Leverage
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Fiscal Quarter Ending
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Coverage Ratio
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Ratio
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March 31, 2009 December 31, 2009
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3.75:1.00
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2.25:1.00
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March 31, 2010 and thereafter
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3.75:1.00
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2.00:1.00
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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 on a four quarter basis. In
general, under the terms of our credit facility, consolidated
adjusted EBITDA is calculated by adding on a consolidated basis,
consolidated net income, consolidated interest expense, income
tax expense, depreciation and amortization, other non- cash
items, 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, major scheduled turnaround expenses and for purposes
of computing the financial ratios (and compliance therewith),
the FIFO adjustment, and then subtracting certain items that
increase consolidated net income. As of March 31, 2009, we
were in compliance with our covenants under the credit facility.
45
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 financial measure 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:
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
|
Consolidated Financial Results
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
172.4
|
|
|
$
|
109.0
|
|
Plus:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
83.4
|
|
|
|
73.8
|
|
Interest expense
|
|
|
40.5
|
|
|
|
60.6
|
|
Income tax expense
|
|
|
69.1
|
|
|
|
(34.4
|
)
|
Funded letters of credit expenses and interest rate swap not
included in interest expense
|
|
|
10.8
|
|
|
|
2.7
|
|
Unrealized (gain) or loss on derivatives, net
|
|
|
(248.3
|
)
|
|
|
5.5
|
|
Non-cash compensation expense for equity awards
|
|
|
(15.4
|
)
|
|
|
25.2
|
|
(Gain) or loss on disposition of fixed assets
|
|
|
5.8
|
|
|
|
1.2
|
|
Unusual or nonrecurring charges
|
|
|
6.9
|
|
|
|
20.0
|
|
Property tax increases due to abatement non-renewal
|
|
|
14.5
|
|
|
|
|
|
FIFO adjustment (unfavorable)(1)
|
|
|
136.7
|
|
|
|
|
|
Loss on extinguishment of debt
|
|
|
10.0
|
|
|
|
1.2
|
|
Minority interest in subsidiaries
|
|
|
|
|
|
|
0.5
|
|
Management fees
|
|
|
|
|
|
|
11.2
|
|
Major scheduled turnaround
|
|
|
3.3
|
|
|
|
10.4
|
|
Goodwill impairment
|
|
|
42.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated adjusted EBITDA
|
|
$
|
332.5
|
|
|
$
|
286.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The amendment to the credit facility entered into on
December 22, 2008 amended the definition of consolidated
adjusted EBITDA to add a FIFO adjustment. This amendment to the
definition first applied for the year ending December 31,
2008 and will apply through the quarter ending
September 30, 2009.
|
In addition to the financial covenants previously mentioned, the
credit facility restricts the capital expenditures of CRLLC and
its subsidiaries to $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 year 2009 if CRLLC
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
46
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 portion of the
collateral, and any party under the credit facility (other than
the agent or lenders under the credit facility) contesting the
validity or enforceability of the credit facility.
The credit facility is subject to an intercreditor agreement
among the lenders and the Cash Flow Swap provider, which deals
with, among other things, priority of liens, payments and
proceeds of sale of collateral.
Capital
Spending
We divide our capital spending needs into two categories:
non-discretionary, which is either capitalized or expensed, and
discretionary, which is capitalized. Non-discretionary capital
spending, such as for planned turnarounds and other maintenance,
is required to maintain safe and reliable operations or to
comply with environmental, health and safety regulations. Our
non-discretionary capital expenditures for the 2009 first
quarter were $6.0 million, of which approximately
$5.5 million was spent in our petroleum business and
$0.5 million in our nitrogen fertilizer business. We
estimate that the total non-discretionary capital spending
needs, including major scheduled turnaround expenses, of our
refinery and the nitrogen fertilizer facilities will be
approximately $58.4 million in the aggregate for 2009. This
estimate includes, among other items, the capital costs
necessary to comply with environmental regulations, including
Tier II gasoline standards. As described above, our credit
facilities limit the amount we can spend on capital expenditures.
We undertake discretionary capital spending based on the
expected return on incremental capital employed. Discretionary
capital projects generally involve an expansion of existing
capacity, improvement in product yields,
and/or
a
reduction in direct operating expenses. We have spent
approximately $8.2 million of discretionary capital spend
for the three months ended March 31, 2009.
Cash
Flows
The following table sets forth our cash flows for the periods
indicated below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
36,673
|
|
|
$
|
24,194
|
|
Investing activities
|
|
|
(15,918
|
)
|
|
|
(26,156
|
)
|
Financing activities
|
|
|
(1,251
|
)
|
|
|
(3,368
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
19,504
|
|
|
$
|
(5,330
|
)
|
|
|
|
|
|
|
|
|
|
Cash
Flows Provided by Operating Activities
Net cash flows from operating activities for the three months
ended March 31, 2009 was $36.7 million. The positive
cash flow from operating activities generated over this period
was primarily driven by $30.7 million of net income,
favorable changes in other working capital, partially offset by
unfavorable changes in trading working capital and other assets
and liabilities over the period. For purposes of this cash flow
discussion, we define trade working capital as accounts
receivable, inventory and accounts payable. Other working
capital is
47
defined as all other current assets and liabilities except trade
working capital. Net income for the period was not indicative of
the operating margins for the period. This is the result of the
accounting treatment of our derivatives in general and, more
specifically, the Cash Flow Swap. We have determined that the
Cash Flow Swap does not qualify as a hedge for hedge accounting
purposes under SFAS No. 133,
Accounting for
Derivative Instruments and Hedging Activities.
Therefore,
the net loss for the three months ended March 31, 2009
included both the realized losses and the unrealized losses on
the Cash Flow Swap. Since the Cash Flow Swap had a significant
term remaining as of March 31, 2009 (approximately one year
and three months) and the NYMEX crack spread that is the basis
for the underlying swaps had increased, the unrealized losses on
the Cash Flow Swap decreased our net income over this period.
Other sources of cash in other working capital included
$34.6 million of restricted cash related to insurance
proceeds, $24.8 million of accrued income taxes,
$11.8 million of additional insurance proceeds partially
offset by a $29.2 million use of cash related to the
payable on the Cash Flow Swap. Trade working capital for the
three months ended March 31, 2009 resulted in a use of cash
of $82.5 million. For the three months ended March 31,
2009, accounts receivable increased $32.3 million,
inventory increased by $24.7 million and accounts payable
decreased by $29.1 million.
Net cash flows from operating activities for the three months
ended March 31, 2008 was $24.2 million. The positive
cash flow from operating activities generated over this period
was primarily driven by favorable changes in other working
capital and other assets and liabilities, partially offset by
unfavorable changes in trading working capital over the period.
For purposes of this cash flow discussion, we define trade
working capital as accounts receivable, inventory and accounts
payable. Other working capital is defined as all other current
assets and liabilities except trade working capital. Net income
for the period was not indicative of the operating margins for
the period. This is the result of the accounting treatment of
our derivatives in general and, more specifically, the Cash Flow
Swap. We have determined that the Cash Flow Swap does not
qualify as a hedge for hedge accounting purposes under
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities.
Therefore, the net loss for the
three months ended March 31, 2008 included both the
realized losses and the unrealized losses on the Cash Flow Swap.
Since the Cash Flow Swap had a significant term remaining as of
March 31, 2008 (approximately two years and three months)
and the NYMEX crack spread that is the basis for the underlying
swaps had increased, the unrealized losses on the Cash Flow Swap
significantly decreased our net income over this period. The
impact of these unrealized losses on the Cash Flow Swap is
apparent in the $20.8 million increase in the payable to
swap counterparty. Other sources of cash in other working
capital included $16.6 million of deferred revenue related
to prepaid fertilizer shipments and a $5.2 million increase
in accrued income taxes. Trade working capital for the three
months ended March 31, 2008 resulted in a use of cash of
$67.5 million. For the three months ended March 31,
2008, accounts receivable increased $30.7 million,
inventory increased by $31.6 million and accounts payable
decreased by $5.2 million.
Cash
Flows Used in Investing Activities
Net cash used in investing activities for the three months ended
March 31, 2009 was $15.9 million compared to
$26.2 million for the three months ended March 31,
2008. The decrease in investing activities for the three months
ended March 31, 2009 as compared to the three months ended
March 31, 2008 was the result of a decline in project
related activity at our petroleum and nitrogen fertilizer
operations.
Cash
Flows Used in Financing Activities
Net cash used for financing activities for the three months
ended March 31, 2009 was $1.3 million as compared to
net cash used in financing activities of $3.4 million for
the three months ended March 31, 2008. During the three
months ended March 31, 2009, we paid $1.2 million of
scheduled principal payments. During the three months ended
March 31, 2008, we paid $1.2 million of scheduled
principal payments and paid $2.1 million of initial public
offering costs related to CVR Partners, LP.
Working
Capital
Working capital at March 31, 2009, was $174.9 million,
consisting of $354.8 million in current assets and
$179.9 million in current liabilities. Working capital at
December 31, 2008 was $128.5 million, consisting of
48
$373.4 million in current assets and $244.9 million in
current liabilities. In addition, we had available borrowing
capacity under our revolving credit facility of
$116.1 million at March 31, 2009.
Letters
of Credit
Our revolving credit facility provides for the issuance of
letters of credit. At March 31, 2009, there were
$33.9 million of irrevocable letters of credit outstanding,
including $3.3 million in support of certain environmental
obligators and $30.6 million to secure transportation
services for crude oil.
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements as of March 31,
2009.
Recent
Accounting Pronouncements
In June 2008, the Financial Accounting Standards Board
(FASB) issued FASB Staff Position (FSP)
Emerging Issues Task Force
(EITF) 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities
, which
became effective January 1, 2009 and is to be applied
retrospectively. Under the FSP, unvested share-based payment
awards which receive non-forfeitable dividend rights, or
dividend equivalents are considered participating securities and
are now required to be included in computing earnings per share
under the two class method. As required we adopted this
statement as of January 1, 2009. Based upon the nature of
our share-based payment awards, it has been determined that
these awards are not participating securities and therefore the
FSP currently has no impact on our earnings per share
calculations.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133.
This statement changes the disclosure
requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about how
and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under
Statement 133 and its related interpretations, and how
derivative instruments and related hedge items affect an
entitys financial position, net earnings, and cash flows.
As required, the Company adopted this statement as of
January 1, 2009. As a result of the adoption, we provided
additional disclosures regarding its derivative instruments in
notes to the condensed consolidated financial statements. There
is no impact on our financial position or results of operation
as a result of this adoption.
In February 2008, the FASB issued FASB Staff Position
157-2
which
defers the effective date of SFAS 157 for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in an entitys
financial statements on a recurring basis (at least annually).
As required, we adopted SFAS 157 as of January 1,
2009. The adoption of SFAS 157 did not impact our financial
position or earnings.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting standards
for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary is an ownership interest
in the consolidated entity that should be reported as equity in
the consolidated financial statements. SFAS 160 requires
retroactive adoption of the presentation and disclosure
requirements for existing noncontrolling interests. All other
requirements of SFAS 160 must be applied prospectively. We
adopted SFAS 160 effective January 1, 2009, and as a
result have classified the noncontrolling interest (previously
minority interest) as a separate component of equity for all
periods presented.
Critical
Accounting Policies
Our critical accounting policies are disclosed in the
Critical Accounting Policies section of our Annual
Report on
Form 10-K
for the year ended December 31, 2008. No modifications have
been made to our critical accounting policies.
49
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
The risk inherent in our market risk sensitive instruments and
positions is the potential loss from adverse changes in
commodity prices and interest rates. Information about market
risks for the three months ended March 31, 2009 does not
differ materially from that discussed under
Part II Item 7A of our Annual Report on
Form 10-K
for the year ended December 31, 2008 . We are exposed to
market pricing for all of the products sold in the future both
at our petroleum business and the nitrogen fertilizer business,
as all of the products manufactured in both businesses are
commodities. As of March 31, 2009, all $483.1 million
of outstanding debt under our credit facility was at floating
rates; accordingly, an increase of 1.0% in our interest rate
would result in an increase in our interest expense of
approximately $4.8 million per year. None of our market
risk sensitive instruments are held for trading.
Our earnings and cash flows and estimates of future cash flows
are sensitive to changes in energy prices. The prices of crude
oil and refined products have fluctuated substantially in recent
years. These prices depend on many factors, including the
overall demand for crude oil and refined products, which in turn
depend on, among other factors, general economic conditions, the
level of foreign and domestic production of crude oil and
refined products, the availability of imports of crude oil and
refined products, the marketing of alternative and competing
fuels, the extent of government regulations and global market
dynamics. The prices we receive for refined products are also
affected by factors such as local market conditions and the
level of operations of other refineries in our markets. The
prices at which we can sell gasoline and other refined products
are strongly influenced by the price of crude oil. Generally, an
increase or decrease in the price of crude oil results in a
corresponding increase or decrease in the price of gasoline and
other refined products. The timing of the relative movement of
the prices, however, can impact profit margins, which could
significantly affect our earnings and cash flows.
|
|
Item 4.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
Our management evaluated, under the direction of our Chief
Executive Officer and Chief Financial Officer, the effectiveness
of our disclosure controls and procedures as defined in Exchange
Act
Rule 13a-15(e)
as of March 31, 2009. Based upon and as of the date of that
evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that our disclosure controls and procedures
were effective, at a reasonable assurance level, to ensure that
information required to be disclosed in the reports we file and
submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported as and when required and is
accumulated and communicated to our management, including our
Chief Executive Officer and our Chief Financial Officer, as
appropriate to allow timely decisions regarding required
disclosure. It should be noted that any system of disclosure
controls and procedures, however well designed and operated, can
provide only reasonable, and not absolute, assurance that the
objectives of the system are met. In addition, the design of any
system of disclosure controls and procedures is based in part
upon assumptions about the likelihood of future events. Due to
these and other inherent limitations of any such system, there
can be no assurance that any design will always succeed in
achieving its stated goals under all potential future conditions.
Changes
in Internal Control Over Financial Reporting
There has been no change in our internal control over financial
reporting required by Exchange Rule Act
Rule 13a-15
that occurred during the fiscal quarter ended March 31,
2009 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
50
Part II.
Other Information
There are no material changes to the risk factors previously
disclosed in our Annual Report on
Form 10-K
for the year ended December 31, 2008 under
Part I Item 1A. Risk Factors.
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.6.1*
|
|
First Amendment to Crude Oil Supply Agreement dated
January 1, 2009 between Vitol, Inc. and Coffeyville
Resources Refining & Marketing, LLC (incorporated
herein by reference to Exhibit 10.6.1 to CVR Energy,
Inc.s Annual Report on
Form 10-K,
for the year ended December 31, 2008, filed on
March 13, 2009.)
|
|
10
|
.47*
|
|
Separation Agreement dated January 23, 2009 between James
T. Rens, CVR Energy, Inc. and Coffeyville Resources, LLC
(incorporated herein by reference to Exhibit 10.47 to CVR
Energy, Inc.s Annual Report on
Form 10-K,
for the year ended December 31, 2008, filed on
March 13, 2009.)
|
|
10
|
.48*
|
|
LLC Unit Agreement dated January 23, 2009 between
Coffeyville Acquisition, LLC, Coffeyville Acquisition II, LLC,
and Coffeyville Acquisition III, LLC and James T. Rens
(incorporated herein by reference to Exhibit 10.48 to CVR
Energy, Inc.s Annual Report on
Form 10-K,
for the year ended December 31, 2008, filed on
March 13, 2009.)
|
|
31
|
.1
|
|
Certification of the Companys Chief Executive Officer
pursuant to
Rule 13a-14(a)
or 15(d)-14(a) under the Securities Exchange Act.
|
|
31
|
.2
|
|
Certification of the Companys Chief Financial Officer
pursuant to
Rule 13a-14(a)
or 15(d)-14(a) under the Securities Exchange Act.
|
|
32
|
.1
|
|
Certification of the Companys Chief Executive Officer
pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2
|
|
Certification of the Companys Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
*
|
|
|
Previously filed.
|
|
|
|
|
Certain portions of this exhibit have been omitted and
separately filed with the SEC pursuant to a request for
confidential treatment which has been granted by the SEC.
|
51
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.
CVR Energy, Inc.
Chief Executive Officer
(Principal Executive Officer)
May 7, 2009
Chief Financial Officer
(Principal Financial Officer)
May 7, 2009
52
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