UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(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, 2008
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
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
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(I.R.S. Employer Identification No.)
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incorporation or organization)
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2277 Plaza Drive, Suite 500
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77479
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Sugar Land, Texas
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(Zip Code)
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(Address of principal executive offices)
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Registrants telephone number, including area code:
(281) 207-3200
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes
þ
No
o
.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
þ
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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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
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There were 86,141,291 shares of the registrants common stock outstanding at May 13, 2008.
CVR ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
For The Quarter Ended March 31, 2008
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
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March 31,
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December 31,
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2008
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2007
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(unaudited)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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25,179
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$
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30,509
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Accounts receivable, net of allowance for doubtful
accounts of $597 and $391, respectively
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117,033
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86,546
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Inventories
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288,415
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254,655
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Prepaid expenses and other current assets
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13,071
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14,186
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Insurance receivable
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74,275
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73,860
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Income tax receivable
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26,166
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31,367
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Deferred income taxes
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78,325
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79,047
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Total current assets
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622,464
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570,170
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Property, plant, and equipment, net of accumulated depreciation
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1,192,542
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1,192,174
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Intangible assets, net
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450
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473
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Goodwill
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83,775
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83,775
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Deferred financing costs, net
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7,028
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7,515
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Insurance receivable
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11,400
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11,400
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Other long-term assets
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5,932
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2,849
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Total assets
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$
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1,923,591
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$
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1,868,356
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LIABILITIES AND EQUITY
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Current liabilities:
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Current portion of long-term debt
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$
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4,862
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$
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4,874
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Note payable and capital lease obligations
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11,209
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11,640
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Payable to swap counterparty
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294,984
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262,415
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Accounts payable
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170,194
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182,225
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Personnel accruals
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34,954
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36,659
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Accrued taxes other than income taxes
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22,073
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14,732
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Deferred revenue
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29,784
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13,161
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Other current liabilities
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32,953
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33,820
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Total current liabilities
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601,013
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559,526
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Long-term liabilities:
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Long-term debt, less current portion
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483,117
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484,328
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Accrued environmental liabilities
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4,924
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4,844
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Deferred income taxes
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287,974
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286,986
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Other long-term liabilities
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4,447
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1,122
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Payable to swap counterparty
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76,411
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88,230
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Total long-term liabilities
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856,873
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865,510
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Commitments and contingencies
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Minority interest in subsidiaries
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10,600
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10,600
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Stockholders equity
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Common stock $0.01 par value per share; 350,000,000
shares authorized;
86,141,291 shares issued and outstanding
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861
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861
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Additional paid-in-capital
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458,523
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458,359
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Retained earning (deficit)
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(4,279
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)
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(26,500
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)
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Total stockholders equity
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455,105
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432,720
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Total liabilities and stockholders equity
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$
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1,923,591
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$
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1,868,356
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See accompanying notes to the condensed consolidated financial statements.
2
CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
(in thousands except share amounts)
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Three months ended
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March 31,
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2008
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2007
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Net sales
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$
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1,223,003
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$
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390,483
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Operating costs and expenses:
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Cost of product sold (exclusive of depreciation and amortization)
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1,036,194
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303,670
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Direct operating expenses (exclusive of depreciation and amortization)
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60,556
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113,412
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Selling, general and administrative expenses
(exclusive of depreciation and amortization)
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13,497
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13,150
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Net costs associated with flood
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5,763
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Depreciation and amortization
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19,635
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14,235
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Total operating costs and expenses
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1,135,645
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444,467
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Operating income (loss)
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87,358
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(53,984
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)
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Other income (expense):
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Interest expense and other financing costs
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(11,298
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)
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(11,857
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)
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Interest income
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702
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452
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Loss on derivatives, net
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(47,871
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)
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(136,959
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Other income, net
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179
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1
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Total other income (expense)
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(58,288
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)
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(148,363
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)
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Income (loss) before income taxes and minority
interest in subsidiaries
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29,070
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(202,347
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)
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Income tax expense (benefit)
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6,849
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(47,298
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)
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Minority interest in loss of subsidiaries
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676
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Net income (loss)
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$
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22,221
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$
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(154,373
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)
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Net earnings per share
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Basic
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$
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0.26
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Diluted
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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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86,141,291
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Diluted
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86,158,791
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Pro Forma Information (note 11)
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Net (loss) per share
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Basic
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$
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(1.79
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)
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Diluted
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$
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(1.79
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)
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Weighted average common shares outstanding
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Basic
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86,141,291
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Diluted
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86,141,291
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See accompanying notes to the condensed consolidated financial statements.
3
CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(in thousands of dollars)
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Three months ended
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March 31,
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2008
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2007
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Cash flows from operating activities:
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Net income (loss)
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$
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22,221
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$
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(154,373
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)
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Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
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Depreciation and amortization
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19,635
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14,235
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Provision for doubtful accounts
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206
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(235
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)
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Amortization of deferred financing costs
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495
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473
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Loss on disposition of fixed assets
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16
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24
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Share-based compensation
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(383
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)
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3,742
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Minority interest in loss of subsidiaries
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(676
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)
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Changes in assets and liabilities:
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Accounts receivable
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(30,693
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)
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44,627
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Inventories
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(31,642
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)
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(22,986
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)
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Prepaid expenses and other current assets
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75
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31
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Insurance receivable
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1,085
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Insurance proceeds from flood
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(1,500
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)
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Other long-term assets
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(3,159
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)
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923
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Accounts payable
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(5,166
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)
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46,357
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Accrued income taxes
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5,201
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14,888
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Deferred revenue
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16,623
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5,067
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Other current liabilities
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5,315
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3,470
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Payable to swap counterparty
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20,750
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129,344
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Accrued environmental liabilities
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80
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|
485
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Other long-term liabilities
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3,325
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Deferred income taxes
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1,710
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(41,291
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)
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Net cash provided by operating activities
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24,194
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44,105
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Cash flows from investing activities:
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Capital expenditures
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(26,156
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)
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(107,363
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)
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Net cash used in investing activities
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(26,156
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)
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(107,363
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)
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Cash flows from financing activities:
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Revolving debt payments
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(123,000
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)
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Revolving debt borrowings
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123,000
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29,500
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Principal payments on long-term debt
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(1,223
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)
|
|
|
|
|
Deferred
costs of CVR Energy, Inc. initial public offering
|
|
|
|
|
|
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(553
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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) provided by financing activities
|
|
|
(3,368
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)
|
|
|
28,947
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(5,330
|
)
|
|
|
(34,311
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)
|
Cash and cash equivalents, beginning of period
|
|
|
30,509
|
|
|
|
41,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Cash and cash equivalents, end of period
|
|
$
|
25,179
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|
|
$
|
7,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
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Cash paid for income taxes, net of refunds (received)
|
|
$
|
(63
|
)
|
|
$
|
(20,895
|
)
|
Cash paid for interest
|
|
|
11,841
|
|
|
|
39
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
Accrual of construction in progress additions
|
|
|
(6,237
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)
|
|
|
13,204
|
|
See
accompanying notes to the condensed consolidated financial statements.
4
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
(1) Organization and History of the Company and Basis of Presentation
Organization
The
Company or CVR may be used to refer to CVR Energy, Inc. and, unless
the context otherwise requires, its subsidiaries. Any references to the Company as of a date
after June 24, 2005 and prior to October 16, 2007 (the date
of the restructuring as further discussed in this note) are to Coffeyville Acquisition LLC (CALLC) and its subsidiaries.
The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner
and marketer in the mid-continental United States and a producer and marketer of upgraded nitrogen
fertilizer products in North America. The Companys operations include two business segments: the
petroleum segment and the nitrogen fertilizer segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in
September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on
October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in
which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in
connection with the initial public offering, CALLC was split into two entities: Coffeyville
Acquisition LLC and Coffeyville Acquisition II LLC (CALLC II).
Initial Public Offering of CVR Energy, Inc.
On October 26, 2007, CVR Energy, Inc. completed an initial public offering of 23,000,000
shares of its common stock. The initial public offering price was $19.00 per share.
The net proceeds to CVR from the initial public offering were approximately $408.5 million,
after deducting underwriting discounts and commissions, but before deduction of offering expenses.
The Company also incurred approximately $11.4 million of other costs related to the initial public
offering. The net proceeds from this offering were used to repay
$280.0 million of term debt under
the Companys credit facility and to repay all indebtedness
under the Companys $25.0 million
unsecured facility and $25.0 million secured facility, including related accrued interest through the
date of repayment of approximately $5.9 million. Additionally,
$50.0 million of net proceeds were
used to repay outstanding revolving loan indebtedness under the Companys credit
facility.
In connection with the initial public offering, CVR became the indirect owner of the
subsidiaries of CALLC and CALLC II. This was accomplished by CVR issuing 62,866,720 shares of its
common stock to CALLC and CALLC II, its majority stockholders, in conjunction with the 628,667.20
for 1 stock split of CVRs common stock and the mergers of two newly formed direct
subsidiaries of CVR into Coffeyville Refining & Marketing
Holdings, Inc. (Refining Holdco) and Coffeyville Nitrogen Fertilizers, Inc. (CNF).
Concurrent with the merger of the subsidiaries and in accordance with a previously executed
agreement, the Companys chief executive officer received 247,471 shares of CVR common
stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully
vested and were exchanged at fair market value.
The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in
connection with the initial public offering. Immediately following the
completion of the offering, there were 86,141,291 shares of common stock outstanding, which does
not include the non-vested shares noted below.
5
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
On October 24, 2007, 17,500 shares of non-vested common stock having a value of $365,000 at
the date of grant were issued to outside directors. Although ownership of the shares does not
transfer to the recipients until the shares have vested, recipients have dividend and voting rights
with respect to these shares from the date of grant. The fair value of each share of non-vested stock was
measured based on the market price of the common stock as of the date of grant and is being
amortized over the respective vesting periods. One-third of the non-vested award will vest on
October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on
October 24, 2010. Options to purchase 10,300 shares of common stock at an exercise price of $19.00
per share were granted to outside directors on October 22, 2007. These awards will vest over a
three year service period. Fair value was measured using an option-pricing model at the date of
grant.
Nitrogen Fertilizer Limited Partnership
In conjunction with the consummation of CVRs initial public offering, CVR transferred
Coffeyville Resources Nitrogen Fertilizer, LLC (CRNF), its nitrogen fertilizer business, to a newly
created limited partnership (Partnership) in exchange for a managing general partner interest
(managing GP interest), a special general partner interest (special GP interest, represented by
special GP units) and a de minimis limited partner interest (LP interest, represented by special LP
units). This transfer was not considered a business combination as it was a transfer of assets
among entities under common control and, accordingly, balances were transferred at their historical
cost. CVR concurrently sold the managing GP interest to Coffeyville
Acquisition LLC III (CALLC III), an entity
owned by CVRs controlling
stockholders and senior management at fair market value. The board of directors of CVR determined,
after consultation with management, that the fair market value of the managing general partner
interest was $10.6 million. This interest has been reflected as minority interest in the
Consolidated Balance Sheet.
CVR
owns all of the interests in the Partnership (other than the managing
general partner interest and the associated incentive distribution
rights (IDRs)) and is
entitled to all cash distributed by the Partnership. The managing general partner is not entitled
to participate in Partnership distributions except with respect to its IDRs, which entitle the
managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership
distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted
to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus,
as defined in the amended and restated partnership agreement, generated by the Partnership through December 31, 2009 has been
distributed in respect of the units held by CVR and any common
units issued in the Partnerships initial public offering. The Partnership and its
subsidiaries are currently guarantors under the credit facility of
Coffeyville Resources, LLC
(CRLLC), a wholly-owned subsidiary of CVR.
The Partnership is operated by CVRs senior management pursuant to a services agreement among
CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing
general partner and, to the extent described below, CVR, as special general partner. As special
general partner of the Partnership, CVR
6
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
has joint management rights regarding the appointment,
termination, and compensation of the chief executive officer and chief financial officer of the
managing general partner, has the right to designate two members of the board of directors of the
managing general partner, and has joint management rights regarding specified major business
decisions relating to the Partnership. CVR, the Partnership, the
managing general partner and various of their subsidiaries also
entered into a number of agreements to regulate certain business
relations between the parties.
At March 31, 2008, the Partnership had 30,333 special LP units outstanding, representing 0.1%
of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding,
representing 99.9% of the total Partnership units outstanding. In addition, the managing general
partner owned the managing general partner interest and the IDRs. The managing general partner
contributed 1% of CRNFs interest to the Partnership in exchange for its managing general partner
interest and the IDRs.
On February 28, 2008, the Partnership filed a registration statement with the Securities and
Exchange Commission (SEC) to effect the contemplated initial public offering of its common units
representing limited partner interests. The registration statement provided that upon consummation
of the Partnerships initial public offering, CVR will indirectly own the Partnerships special
general partner and approximately 87% of the outstanding units of the Partnership. There can be no
assurance that any such offering will be consummated on the terms described in the registration
statement or at all. The offering is under review by the SEC and as a result the terms and
resulting structure disclosed below could be materially different.
In connection with the Partnerships initial public offering, CRLLC will contribute all of its
special LP units to the Partnerships special general partner and all of the Partnerships special
general partner interests and special limited partner interests will be converted into a
combination of GP units and subordinated GP units. Following the
initial public offering, as currently structured, the
Partnership is expected to have the following partnership interests outstanding:
|
5,250,000 common units representing limited partner interests, all of which the
Partnership will sell in the initial public offering;
|
|
|
18,750,000 GP units representing special general partner interests, all of which will
be held by the Partnerships special general partner;
|
|
|
18,000,000 subordinated GP units representing special general partner interests, all
of which will be held by the Partnerships special general
partner; and
|
|
|
a managing general partner interest, which is not entitled to any distributions, which
is held by the Partnerships managing general partner, and incentive distribution rights representing limited partner interests, all of which
will be held by the Partnerships managing general partner.
|
Effective with the Partnerships initial public offering, the partnership agreement will
require that the Partnership distribute all of its cash on hand at the end of each quarter, less
reserves established by its managing general partner, subject to a sustainability requirement in
the event the Partnership elects to increase the quarterly distribution amount. The amount of
available cash may be greater or less than the aggregate amount necessary to make the minimum
quarterly distribution on all common units, GP units and subordinated units.
Subsequent to the initial public offering, as currently structured, the Partnership expects to make minimum quarterly
distributions of $0.375 per common unit ($1.50 per common unit on an annualized basis) to the
extent the Partnership has sufficient available cash. In general, cash distributions will be made
each quarter as follows:
|
First, to the holders of common units and GP units until each common unit and GP unit
has received a minimum quarterly distribution of $0.375 plus any arrearages from prior
quarters;
|
7
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
|
|
|
Second, to the holders of subordinated units, until each subordinated unit has
received a minimum quarterly distribution of $0.375; and
|
|
|
|
|
Third, to all unitholders, pro rata, until each unit has received a quarterly
distribution of $0.4313.
|
If cash distributions exceed $0.4313 per unit in a quarter, the Partnerships managing general
partner, as holder of the IDRs, will receive increasing percentages, up to 48%, of the cash the
Partnership distributes in excess of $0.4313 per unit. However, the managing general partner will
not be entitled to receive any distributions in respect of the IDRs until the Partnership has made
cash distributions in an aggregate amount equal to the Partnerships adjusted operating surplus
generated during the period from the closing of the Partnerships initial public offering until December 31,
2009.
During the subordination period, the subordinated units will not be entitled to receive any
distributions until the common units and GP units have received the minimum quarterly distribution
of $0.375 per unit plus any arrearages from prior quarters. The subordination period begins on the closing date of the Partnerships initial public offering and will end once
the Partnership meets the financial tests in the partnership agreement. When the subordination period ends, all subordinated units will convert into GP units or
common units on a one-for-one basis, and the common units and GP units will no longer be entitled
to arrearages.
If the Partnership meets the financial tests in the partnership agreement for any three
consecutive four-quarter periods ending on or after the first quarter whose last day is at least
three years after the closing of Partnership Offering, 25% of the subordinated GP units will
convert into GP units on a one-for-one basis. If the Partnership meets these financial tests for
any three consecutive four-quarter periods ending on or after the first quarter whose last day is
at least four years after the closing of the Partnership Offering, an additional 25% of the
subordinated GP units will convert into GP units on a one-for-one basis. The early conversion of
the second 25% of the subordinated GP units may not occur until at least one year following the end
of the last four-quarter period in respect of which the first 25% of the subordinated GP units were
converted. If the subordinated GP units have converted into subordinated LP units at the time the
financial tests are met they will convert into common units, rather than GP units. In addition, the
subordination period will end if the managing general partner is removed as the managing general
partner where cause (as defined in the partnership agreement) does not exist and no units held by
any holder of subordinated units or its affiliates are voted in favor of that removal.
The partnership agreement authorizes the Partnership to issue an unlimited number of
additional units and rights to buy units for the consideration and on the terms and conditions
determined by the managing general partner without the approval of the unitholders.
The Partnership will distribute all cash received by it or its subsidiaries in respect of
accounts receivable existing as of the closing of the initial public offering exclusively to its
special general partner.
The managing general partner, together with the special general partner, manages and operates
the Partnership. Common unitholders will only have limited voting rights on matters affecting the
Partnership. In addition, common unitholders will have no right to elect either of the general
partners or the managing general partners directors on an annual or other continuing basis.
If at any time the managing general partner and its affiliates own more than 80% of the common
units, the managing general partner will have the right, but not the obligation, to purchase all of
the remaining common units at a purchase price equal to the greater of (x) the average of the daily
closing price of the common units over the 20 trading days preceding the date three days before
notice of exercise of the call right is first mailed and (y) the highest per-unit price paid by the
managing general partner or any of its affiliates for common units during the 90-day period
preceding the date such notice is first mailed.
8
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements were prepared in
accordance with U.S. generally accepted accounting principles (GAAP) and in accordance with the
rules and regulations of the SEC. The consolidated financial statements include the accounts of
CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interests of
minority investors in its subsidiaries are recorded as minority interest. All intercompany
accounts and transactions have been eliminated in consolidation. Certain information and footnotes
required for the complete financial statements under GAAP have been condensed or omitted pursuant
to such rules and regulations. These unaudited condensed consolidated financial statements should
be read in conjunction with the December 31, 2007 audited consolidated financial statements and
notes thereto included in CVRs Annual Report on Form 10-K/A for the year ended December 31, 2007.
In the opinion of the Companys management, the accompanying unaudited condensed consolidated
financial statements reflect all adjustments (consisting only of normal recurring adjustments) that
are necessary to fairly present the financial position of the Company as of March 31, 2008 and
December 31, 2007, the results of operations for the three months ended March 31, 2008 and 2007,
and the cash flows for the three months ended March 31, 2008 and 2007.
Results of operations and cash flows for the interim periods presented are not necessarily
indicative of the results that will be realized for the year ending December 31, 2008 or any other
interim period. The preparation of financial statements in conformity
with U.S. generally accepted accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of
contingent assets and liabilities. Actual results could differ from those estimates.
In
connection with CVRs initial public offering, $0.5 million
of deferred offering costs for the three months ended
March 31, 2007 were previously presented in operating activities
in the interim financial statements. Such amounts have now been
reflected as financing activities for the three months ended
March 31, 2007 in the accompanying Consolidated Statements of
Cash Flows. The impact on the prior financial statements of this
revision is not considered material.
(2) Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement on
Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements
, which establishes a
framework for measuring fair value in GAAP and expands disclosures about fair value measurements.
SFAS 157 states that fair value is the price that would be received to sell the asset or paid to
transfer the liability (an exit price), not the price that would be paid to acquire the asset or
received to assume the liability (an entry price). The standards provisions for financial assets
and financial liabilities, which became effective January 1, 2008, had no material impact on the
Companys financial position or results of operations. At March 31, 2008, the only financial
assets and financial liabilities that are measured at fair value on a recurring basis are the
Companys derivative instruments. See Note 14, Fair Value
Measurements.
In
February 2008, the FASB issued FASB Staff Position 157-2 which defers the effective date of
SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized
or disclosed at fair value in an entitys financial statements on a recurring basis (at least
annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and
nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157
deferral provisions will not have a material impact on the Companys financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and
Financial Liabilities
. Under this standard, an entity is required to provide additional
information that
will assist investors and other users of financial information to more easily understand the
effect of the Companys choice to use fair value on its earnings. Further, the entity is required
to display the fair value of those assets and liabilities for which the Company has chosen to use
fair value on the face of the balance sheet. This standard does not eliminate the disclosure
requirements about fair value measurements included in SFAS No. 107,
Disclosures about Fair Value of
Financial Instruments
. The provisions of SFAS 159 were effective for CVR as of January 1, 2008.
The Company did not elect the fair value option under this standard
upon adoption. Therefore, the
adoption of SFAS 159 did not impact the Companys consolidated
financial statements as of the quarter
ended March 31, 2008.
9
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
. This statement
defines the acquirer as the entity that obtains control of one or more businesses in the business
combination, establishes the acquisition date as the date that the acquirer achieves control and
requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling
interest at their fair values as of the acquisition date. This statement also requires that
acquisition-related costs of the acquirer be recognized separately from the business combination
and will generally be expensed as incurred. CVR will be required to adopt this statement as of
January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business
combinations for which the acquisition date is on or after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated
Financial Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting
standards for the non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest
in the consolidated entity that should be reported as equity in the consolidated financial
statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements
for existing minority interests. All other requirements of SFAS 160 must be applied prospectively.
SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the
potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In
March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB
Statement No. 133
. This statement will change the disclosure requirements for derivative
instruments and hedging activities. Entities are required to provide enhanced disclosures
about how and why an entity uses derivative instruments, how derivative instruments and
related hedged items are accounted for under Statement 133 and its related interpretations,
and how derivative instruments and related hedged items affect an entitys financial position,
net earnings, and cash flows. The Company will be required to adopt this statement as of January
1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Companys consolidated financial
statements.
(3) Share Based Compensation
Prior to CVRs initial public offering, CVRs subsidiaries were held and operated by CALLC, a
limited liability company. Management of CVR holds an equity interest in CALLC. CALLC had issued
non-voting override units to certain management members who held common units of CALLC. There were
no required capital contributions for the override operating units.
In connection with CVRs
initial public offering in October 2007, CALLC was split into two entities: CALLC and CALLC II. In
connection with this split, managements equity interest in CALLC, including both their common units and
non-voting override units, was split so that half of managements equity interest was in
CALLC and half was in CALLC II. CALLC was historically the primary reporting company and CVRs
predecessor. In connection with the restructuring of the Company
related to the Partnership, CALLC III
issued non-voting override units to certain management members
of CALLC III.
CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with
SFAS No. 123(R),
Share-Based Payments
and EITF 00-12,
Accounting by an Investor for
Stock-Based Compensation Granted to Employees of an Equity Method Investee
. CVR has
recorded non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.
In
accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair value based
measurement method in accounting for share-based compensation. In accordance with EITF 00-12, CVR
recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on
its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation
and amortization), and a corresponding capital contribution, as the costs are incurred on its
behalf, following the guidance in EITF 96-18,
Accounting for Equity Investments That Are
Issued to Other Than Employees for Acquiring, or in Conjunction with
10
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
Selling Goods or Services
,
which requires remeasurement at each reporting period. At March 31, 2008, CVRs common stock
closing price was utilized to determine the fair value of the
override units of CALLC and CALLC II. The estimated fair value
per unit reflects a ratio of override units to shares of common
stock. The estimated fair value of the override units of
CALLC III has been determined using a binomial and
probability-weighted expected return method which utilizes
CALLC IIIs
cash flow projections, which are representative of the nature of
interests held by CALLC III in the Partnership.
The following describes the share-based compensation plans of CALLC, CALLC II, CALLC III and CRLLC,
CVRs indirect wholly owned subsidiary.
919,630 override operating units at an adjusted benchmark value of $11.31 per unit
In June 2005, CALLC issued 919,630 non-voting override operating units to certain management
members holding common units of CALLC. There were no required capital contributions for the
override operating units.
In accordance with SFAS 123(R),
Share Based Compensation
, using the Monte Carlo method of
valuation, the estimated fair value of the override operating units on June 24, 2005 was
$3,605,000. Pursuant to the forfeiture schedule described below, CVR recognized compensation
expense over the service period for each separate portion of the award for which the forfeiture
restriction lapsed as if the award was, in substance, multiple awards. Compensation expense of
$(558,000) and $285,000 was recognized for the three months ending March 31, 2008 and 2007,
respectively.
In connection with the split of CALLC into two entities on October 16, 2007, managements
equity interest in CALLC was split so that half of managements equity interest is in CALLC and
half is in CALLC II. The restructuring resulted in a modification of the existing awards under
SFAS 123(R). However, because the fair value of the modified award equaled the fair value of the
original award before the modification, there was no accounting consequence as a result of the
modification. However, due to the restructuring, the employees of CVR
and the Partnership no
longer hold share-based awards in a parent company. Due to the change in status of the employees
related to the awards, CVR recognized compensation expense for the newly measured cost
attributable to the remaining vesting (service) period prospectively from the date of the change in
status.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture
|
|
Based on forfeiture
|
|
|
schedule below
|
|
schedule below
|
Grant date fair value
|
|
$5.16 per share
|
|
N/A
|
March 31,
2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$47.88 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
N/A
|
72,492 override operating units at a benchmark value of $34.72 per unit
On December 28, 2006, CALLC issued 72,492 additional non-voting override operating units to a
management member who held common units of CALLC. There were no required capital contributions for
the override operating units.
11
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted
expected return method which utilized CVRs cash flow projections resulted in an estimated
fair value of the override operating units on December 28, 2006 of $473,000. Management believed
that this method was preferable for the valuation of the override units as it allowed a better
integration of the cash flows with other inputs, including the timing of potential exit events that
impact the estimated fair value of the override units. These override operating units are being
accounted for the same as the override operating units with the adjusted benchmark value of $11.31
per unit. In accordance with the accounting method noted above and pursuant to the forfeiture
schedule described below, CVR recognized compensation expense of $6,000 and $100,000 for the
periods ending March 31, 2008 and 2007, respectively.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Explicit service period
|
|
Based on forfeiture
|
|
Based on forfeiture
|
|
|
schedule below
|
|
schedule below
|
Grant date fair value
|
|
$8.15 per share
|
|
N/A
|
March 31, 2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$28.68 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
N/A
|
Override operating units are forfeited upon termination of employment for cause. In the event
of all other terminations of employment, the override operating units are initially subject to
forfeiture with the number of units subject to forfeiture reducing as follows:
|
|
|
|
|
Minimum
|
|
Forfeiture
|
Period Held
|
|
Rate
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
On the tenth anniversary of the issuance of override operating units, such units convert
into an equivalent number of override value units.
1,839,265 override value units at an adjusted benchmark value of $11.31 per unit
In June 2005, CALLC issued 1,839,265 non-voting override value units to certain management
members who held common units of CALLC. There were no required capital contributions for the
override value units.
In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair
value of the override value units on June 24, 2005 was $4,065,000. For the override value units,
CVR is recognizing compensation expense ratably over the implied service period of 6 years.
These override value units are being accounted for the same as the override operating units with an
adjusted benchmark value of $11.31 per unit. In
12
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
accordance
with the accounting method noted above,
CVR recognized compensation expense of $533,000 and $169,000 for the three months ending March 31,
2008 and 2007, respectively.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$2.91 per share
|
|
N/A
|
March 31, 2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$47.88 per share
|
Marketability and minority interest discounts
|
|
24% discount
|
|
15% discount
|
Volatility
|
|
37%
|
|
N/A
|
144,966 override value units at a benchmark value of $34.72 per unit
On December 28, 2006, CALLC issued 144,966 additional non-voting override value units to a
management member who held common units of CALLC. There were no required capital contributions for
the override value units.
In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted
expected return method which utilized CVRs cash flow projections resulted in an estimated
fair value of the override value units on December 28, 2006 of $945,000. Management believed that
this method was preferable for the valuation of the override units as it allowed a better
integration of the cash flows with other inputs, including the timing of potential exit events that
impacted the estimated fair value of the override units. These override value units are being
accounted for the same as the override operating units with the adjusted benchmark value of $11.31
per unit. In accordance with the accounting method noted above, CVR recognized compensation
expense of $91,000, and $52,000 for the three months ending March 31, 2008 and 2007, respectively.
Significant assumptions used in the valuation were as follows:
|
|
|
|
|
|
|
Grant
|
|
Remeasurement
|
|
|
Date
|
|
Date
|
Estimated forfeiture rate
|
|
None
|
|
None
|
Derived service period
|
|
6 years
|
|
6 years
|
Grant date fair value
|
|
$8.15 per share
|
|
N/A
|
March 31, 2008 CVR closing stock price
|
|
N/A
|
|
$23.03
|
March 31, 2008 estimated fair value
|
|
N/A
|
|
$28.68 per share
|
Marketability and minority interest discounts
|
|
20% discount
|
|
15% discount
|
Volatility
|
|
41%
|
|
N/A
|
Unless the compensation committee of the board of directors of CVR takes an action to
prevent forfeiture, override value units are forfeited upon termination of employment for any
reason except that in the event of termination of employment by reason of death or disability, all
override value units are initially subject to forfeiture with the number of units subject to
forfeiture reducing as follows:
13
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
|
|
|
|
|
Minimum
|
|
Subject to
|
period
|
|
forfeiture
|
held
|
|
percentage
|
2 years
|
|
|
75
|
%
|
3 years
|
|
|
50
|
%
|
4 years
|
|
|
25
|
%
|
5 years
|
|
|
0
|
%
|
At March 31, 2008, assuming no change in the estimated fair value at March 31, 2008, there was
approximately $59.2 million of unrecognized compensation expense related to non-voting override
units. This is expected to be recognized over a remaining period of four years as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Override
|
|
|
Override
|
|
|
|
Operating Units
|
|
|
Value Units
|
|
Nine months ending December 31, 2008
|
|
$
|
4,927
|
|
|
$
|
11,688
|
|
Year ending December 31, 2009
|
|
|
3,762
|
|
|
|
15,585
|
|
Year ending December 31, 2010
|
|
|
1,120
|
|
|
|
15,584
|
|
Year ending December 31, 2011
|
|
|
|
|
|
|
6,569
|
|
|
|
|
|
|
|
|
|
|
$
|
9,809
|
|
|
$
|
49,426
|
|
|
|
|
|
|
|
|
138,281 override units with a benchmark amount of $10
In October 2007, CALLC III issued 138,281 non-voting override units to certain management
members who held common units of CALLC III. There were no required capital contributions for the
override units.
In accordance with SFAS 123(R),
Share Based Compensation
, using a binomial and a
probability-weighted expected return method which utilized CALLC IIIs cash flow projections,
the estimated fair value of the operating units at March 31,
2008 was immaterial. CVR recognizes
compensation costs for this plan based on the fair value of the awards at the end of each reporting
period in accordance with EITF 00-12 using the guidance in EITF 96-18. In accordance with
EITF 00-12, as a noncontributing investor, CVR also recognized income equal to the amount
that its interest in the Partnerships net book value has increased (that is, its percentage share of
the contributed capital recognized by the investee) as a result of the disproportionate funding of
the compensation costs. This amount equaled the compensation expense recognized for these awards
for the three months ended March 31, 2008. Pursuant to the forfeiture schedule reflected above,
CVR recognized compensation expense over this service period for each portion of the award
for which the forfeiture restriction has lapsed. As of March 31,
2008, these override units are fully vested.
Significant
assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
March 31, 2008 estimated fair value
|
|
$0.004 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
36.2%
|
14
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
642,219 override units with a benchmark amount of $10
On February 15, 2008, CALLC III issued 642,219 non-voting override units to certain management
members of CALLC III. There were no required capital contributions for the
override units.
In accordance with SFAS 123(R),
Share Based Compensation,
using a binomial and a
probability-weighted expected return method which utilized CALLC IIIs cash flows projections,
the estimated fair value of the operating units at March 31,
2008 was immaterial. CVR recognizes
compensation costs for this plan based on the fair value of the awards at the end of each reporting
period in accordance with EITF 00-12 using the guidance in EITF 96-18. In accordance with
EITF 00-12, as a noncontributing investor, CVR also recognized income equal to the amount
that its interest in the investees net book value has increased (that is, its percentage share of
the
contributed capital recognized by the investee) as a result of the disproportionate funding of
the compensation costs. CVR recognized compensation expense of $600 for the three months ended
March 31, 2008. Pursuant to the forfeiture schedule of the amended and restated partnership
agreement of CALLC III, CVR recognized
compensation expense over this service period for each portion of the award for which the
forfeiture restriction has lapsed. Of the 642,219 units issued,
109,720 were immediately vested upon issuance and the remaining units
are subject to the forfeiture schedule.
Significant
assumptions used in the valuation were as follows:
|
|
|
Estimated forfeiture rate
|
|
None
|
Derived Service Period
|
|
Based on forfeiture schedule
|
March 31, 2008 estimated fair value
|
|
$0.004 per share
|
Marketability and minority interest discount
|
|
15% discount
|
Volatility
|
|
36.2%
|
Phantom Unit Appreciation Plan
The Company, through a wholly-owned subsidiary, has a Phantom Unit Appreciation Plan whereby
directors, employees, and service providers may be awarded phantom points at the discretion of the
board of directors or the compensation committee. Holders of service phantom points have rights to
receive distributions when holders of override operating units receive distributions. Holders of
performance phantom points have rights to receive distributions when holders of override value
units receive distributions. There are no other rights or guarantees, and the plan expires on July
25, 2015 or at the discretion of the compensation committee of the board of directors. As of March
31, 2008, the issued Profits Interest (combined phantom plan and override units) represented 15% of
combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was
comprised of 11.1% and 3.9% of override interest and phantom interest, respectively. In accordance
with SFAS 123(R), using the March 31, 2008 CVR stock closing price to determine the
Companys equity value, through an independent valuation process, the service phantom interest and
performance phantom interest were both valued at $47.88 per point. CVR has recorded
approximately $28,670,000 and $29,217,000 in personnel accruals as of March 31, 2008 and December
31, 2007, respectively. Compensation expense for the three month periods ending March 31, 2008 and
2007 related to the Phantom Unit Appreciation Plan was $(547,000) and $3,136,000, respectively.
At
March 31, 2008, assuming no change in the estimated fair value at March 31, 2008, there was
approximately $20.6 million of unrecognized compensation expense
related to the Phantom Unit Appreciation Plan.
This is expected to be recognized over a remaining period of four years.
Long Term Incentive Plan
CVR has a Long Term Incentive Plan. There were no awards granted under this plan in
the first quarter of 2008.
15
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
On October 24, 2007, 17,500 shares of non-vested common stock having a fair value of $365,000
at the date of grant were issued to outside directors. Although ownership of the shares does not
transfer to the recipients until the shares have vested, recipients have dividend and voting rights
on these shares from the date of grant. The fair value of each share of non-vested common stock was
measured based on the market price of the common stock as of the date of grant and will be
amortized over the respective vesting periods. One-third will vest on
October 24, 2008, 2009 and 2010, respectively.
Options to purchase 10,300 shares of common stock at an exercise price of $19.00 per share
were granted to outside directors on October 22, 2007. Options to purchase 8,600 shares of common
stock at an exercise price of $24.73 per share were granted to outside directors on December 21,
3007.
During the quarter there were no issuances, forfeitures or vesting of stock options or non-vested
shares.
As of March 31, 2008, there was approximately $0.2 million of total unrecognized compensation
cost related to non-vested shares to be recognized over a weighted-average period of approximately
one year. Compensation expense recorded for the three month periods ending March 31, 2008 and 2007
related to the non-vested stock was $56,000 and $0, respectively. Compensation expense for the
three month periods ending March 31, 2008 and 2007 related to stock options was $36,000 and $0,
respectively.
(4) Inventories
Inventories consist primarily of crude oil, blending stock and components, work in progress,
fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of the
first-in, first-out (FIFO) cost, or market, for fertilizer products, refined fuels and by-products
for all periods presented. Refinery unfinished and finished products inventory values were
determined using the ability-to-bare process, whereby raw materials and production costs are
allocated to work-in-process and finished products based on their relative fair values. Other
inventories, including other raw materials, spare parts, and supplies, are valued at the lower of
moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound
freight costs.
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
Finished goods
|
|
$
|
123,814
|
|
|
$
|
109,394
|
|
Raw materials and catalysts
|
|
|
123,042
|
|
|
|
92,104
|
|
In-process inventories
|
|
|
17,045
|
|
|
|
29,817
|
|
Parts and supplies
|
|
|
24,514
|
|
|
|
23,340
|
|
|
|
|
|
|
|
|
|
|
$
|
288,415
|
|
|
$
|
254,655
|
|
|
|
|
|
|
|
|
(5) Property, Plant, and Equipment
A summary of costs for property, plant, and equipment is as follows (in thousands):
16
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
Land and improvements
|
|
$
|
13,170
|
|
|
$
|
13,058
|
|
Buildings
|
|
|
19,351
|
|
|
|
17,541
|
|
Machinery and equipment
|
|
|
1,277,292
|
|
|
|
1,108,858
|
|
Automotive equipment
|
|
|
5,752
|
|
|
|
5,171
|
|
Furniture and fixtures
|
|
|
6,420
|
|
|
|
6,304
|
|
Leasehold improvements
|
|
|
929
|
|
|
|
929
|
|
Construction in progress
|
|
|
30,859
|
|
|
|
182,046
|
|
|
|
|
|
|
|
|
|
|
|
1,353,773
|
|
|
|
1,333,907
|
|
Accumulated depreciation
|
|
|
161,231
|
|
|
|
141,733
|
|
|
|
|
|
|
|
|
|
|
$
|
1,192,542
|
|
|
$
|
1,192,174
|
|
|
|
|
|
|
|
|
Capitalized interest recognized as a reduction in interest expense for the periods ended March
31, 2008, and March 31, 2007 totaled approximately $1,118,000
and $4,079,000, respectively.
(6) Planned Major Maintenance Costs
The direct-expense method of accounting is used for planned major maintenance activities.
Maintenance costs are recognized as expense when maintenance services are performed. The
Coffeyville nitrogen fertilizer plant last completed a major scheduled turnaround in the third
quarter of 2006 and is scheduled to complete a turnaround in the fourth quarter of 2008. The
Coffeyville refinery started a major scheduled turnaround in February 2007 with completion in April
2007. Costs of $66,003,000 associated with the 2007 refinery turnaround were included in direct
operating expenses (exclusive of depreciation and amortization) for the three months ending March
31, 2007.
(7) Cost Classifications
Cost
of product sold (exclusive of depreciation and amortization) includes cost of crude oil,
other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of
product sold excludes depreciation and amortization of $600,000 and $619,000 for the three months
ended March 31, 2008 and March 31, 2007, respectively.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs
of labor, maintenance and services, energy and utility costs, environmental compliance costs as
well as chemicals and catalysts and other direct operating expenses. Direct operating expenses
excludes depreciation and amortization of $18,703,000 and $13,530,000 for the three months ended
March 31, 2008 and March 31, 2007, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization)
consists primarily of legal expenses, treasury, accounting, marketing, human resources and
maintaining the corporate offices in Texas and Kansas. Selling, general and administrative
expenses excludes depreciation and amortization of $332,000 and $86,000 for the three months ended
March 31, 2008 and March 31, 2007, respectively.
(8) Note Payable and Capital Lease Obligations
The Company entered into an insurance premium finance agreement with Cananwill, Inc. in July
2007 to finance the purchase of its property, liability, cargo and terrorism policies. The
original balance of the note was $7.6 million and required repayment in nine equal installments
with final payment due in April 2008. The balance due was paid in full in April 2008. As of March
31, 2008 and December 31, 2007, $0.8 and $3.4 million related to this
17
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
insurance premium finance
agreement was included in note payable and capital lease obligations on the Consolidated Balance
Sheet, respectively.
The Company entered into two capital leases in 2007 to lease platinum required in the
manufacturing of a new catalyst. The recorded lease obligations fluctuate with the platinum market
price. The leases will terminate on the date an equal amount of platinum is returned to each
lessor, with the difference to be paid in cash. One lease was settled and terminated in January
2008. At March 31, 2008 and December 31, 2007 the lease obligations were recorded at approximately
$10.4 million and $8.2 million on the Consolidated Balance Sheets, respectively.
(9) Flood and Insurance Related Matters
On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow
its banks and flood the town of Coffeyville, Kansas. As a result, the Companys refinery and
nitrogen fertilizer plant were severely flooded, resulting in significant damage to the refinery
assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The
Company maintained property damage insurance which included damage caused by a flood, of up to $300
million per occurrence, subject to deductibles and other limitations. The deductible associated
with the property damage was $2.5 million.
Management continues to work closely with the Companys insurance carriers and claims
adjusters to ascertain the full amount of insurance proceeds due to the Company as a result of the
damages and losses. At March 31, 2008, total accounts receivable from insurance was $85.7 million.
The receivable balance is segregated between current and long-term in the Companys Consolidated
Balance Sheet in relation to the nature and classification of the items to be settled. Management
believes the recovery of the receivable from the insurance carriers is probable. Approximately $11.4
million of the receivable recorded at March 31, 2008 relates to the crude oil discharge and the
remaining $74.3 million relates to the flood damage to the Companys facilities. While management
believes that the Companys property insurance should cover substantially all of the estimated
total physical damage to the property, the Companys insurance carriers have cited potential
coverage limitations and defenses that might preclude such a result.
The Companys insurance policies also provide coverage for interruption to the business,
including lost profits, and reimbursement for other expenses and costs the Company has incurred
relating to the damages and losses suffered for business interruption. This coverage, however,
only applies to losses incurred after a business interruption of 45 days. Because the fertilizer
plant was restored to operation within this 45-day period and the refinery restarted its last
operating unit in 48 days, a substantial portion of the lost profits incurred because of the flood
cannot be claimed under insurance. The Company continues to assess its policies to determine how
much, if any, of its lost profits after the 45-day period are recoverable. No amounts for recovery
of lost profits under the Companys business interruption policy have been recorded in the
accompanying consolidated financial statements.
The Company has recorded pretax costs in total of
approximately $47.3 million associated with the flood and related crude oil discharge as discussed
in Note 12, Commitments and Contingent Liabilities,
including $5.8 million of net pretax costs in the first quarter
of 2008. These amounts are net of
anticipated insurance recoveries of $107.2 million including $1.8 million of recoveries for the first quarter of 2008. These costs are reported in Net costs
associated with flood in the Consolidated Statements of Operations.
Total gross costs recorded due to the flood and related oil discharge that were included in
the Consolidated Statements of Operations for the three months ended March 31, 2008 were $7.6
million. Of these gross costs for the three month period ended March 31, 2008, $3.8 million were
associated with repair and other matters as a result of the flood damage to the Companys
facilities. Included in this cost was $ 0.3 million of professional fees and $3.5 million for
other repair and related costs. There were also $3.8 million of costs recorded for the three month period
ended March 31, 2008 related to the third party and property damage remediation as a result of the
crude oil discharge.
Below
is a summary of the gross cost and reconciliation of the insurance
receivable (in millions):
|
|
|
|
|
|
|
|
|
|
|
Total
Costs
|
|
For the Three Months
Ended
March 31, 2008
|
Total gross
costs incurred
|
|
$
|
154.5
|
|
|
$
|
7.6
|
|
Total
insurance receivable
|
|
|
(107.2
|
)
|
|
|
(1.8
|
)
|
|
|
|
|
|
|
|
Net costs
associated with the flood
|
|
$
|
47.3
|
|
|
$
|
5.8
|
|
|
|
|
|
|
|
|
Receivable
Reconciliation
|
Total
insurance receivable
|
|
$
|
107.2
|
|
Less
insurance proceeds received
|
|
|
(21.5
|
)
|
|
|
|
|
Insurance
receivable
|
|
$
|
85.7
|
|
The Company anticipates that approximately $2.1 million in additional third party costs
related to the repair of flood damaged property will be recorded in future periods. Although the
Company believes that it will recover
18
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
substantial sums under its insurance policies, the Company is
not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in
projecting the ultimate resolution of the Companys claims. The difference between what the
Company ultimately receives under its insurance policies compared to what has been recorded and
described above could be material to the consolidated financial statements.
In
2007, the Company had received insurance proceeds of $10.0 million under its property
insurance policy and $10.0 million under its environmental policies related to recovery of certain
costs associated with the crude oil discharge. In the first quarter
of 2008, the Company received $1.5
million under its Builders Risk Insurance Policy. See Note 12, Commitments and Contingent
Liabilities for additional information regarding environmental and other contingencies relating to
the crude oil discharge that occurred on July 1, 2007.
(10) Income Taxes
The Company adopted the provisions of FASB Interpretation No. 48,
Accounting for Uncertain Tax
Positions an interpretation of FASB No. 109
(FIN 48) on January 1, 2007. The adoption of FIN 48
did not affect the Companys financial position or results of operations. The Company does not
have any unrecognized tax benefits as of March 31, 2008.
The Company did not accrue or recognize any amounts for interest or penalties in its financial
statements for the three months ended March 31, 2008. The Company will classify interest to be
paid on an underpayment of income taxes and any related penalties as income tax expense if it is
determined, in a subsequent period, that a tax position is not more likely than not of being
sustained.
CVR and its subsidiaries file U.S. federal and various state income tax returns. The
Company is currently under a U.S. federal income tax examination for its 2005 tax year. The
Company has not been subject to any other U.S. federal, state or local income tax examinations by
tax authorities for any tax year. The U.S. federal and state tax years subject to examination are
2004 to 2007. As of March 31, 2008, no taxing authority has proposed any adjustments to the
Companys tax positions.
The Companys effective tax rates for the three months ended March 31, 2008 and 2007 were 23.6%
and 23.4%, respectively, as compared to the federal statutory tax rate of 35%. The effective tax
rate is lower than the statutory rate due to federal income tax credits available to small business
refiners related to the production of ultra low sulfur diesel fuel and Kansas state incentives
generated under the High Performance Incentive Program (HPIP).
(11) Earnings (Loss) Per Share
On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of
its common stock. Also, in connection with the initial public offering, a reorganization of
entities under common control was consummated whereby the Company became the indirect owner of the
subsidiaries of CALLC and CALLC II and all of their refinery and fertilizer assets. This
reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to
CALLC and CALLC II, its majority stockholders, in conjunction with a
628,667.20 for 1 stock split and the merger of two newly formed
direct subsidiaries of CVR. Immediately following the completion of the offering, there were
86,141,291 shares of common stock outstanding, excluding non-vested shares issued. See Note 1,
Organization and History of Company and Basis of Presentation.
Earnings per share for the three months ended March 31, 2008 is calculated as noted below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
Shares
|
|
Per Share
|
Basic earnings per share
|
|
$
|
22,221,000
|
|
|
|
86,141,291
|
|
|
$
|
0.26
|
|
Diluted earnings per share
|
|
$
|
22,221,000
|
|
|
|
86,158,791
|
|
|
$
|
0.26
|
|
Outstanding
stock options totaling 18,900 common shares were excluded from the
diluted earnings per share calculation for the three months ended
March 31, 2008 as they were antidilutive.
19
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
The computation of basic and diluted loss per share for the quarter ended March 31, 2007 is
calculated on a pro forma basis assuming the capital structure in place after the completion of the
offering was in place for the entire period.
Pro forma loss per share for the three months ended March 31, 2007 is calculated as noted
below. For the three months ended March 31, 2007, 17,500 non-vested shares of common stock and
18,900 common stock options have been excluded from the calculation of pro forma diluted earnings
per share because the inclusion of such common stock equivalents in the number of weighted average
shares outstanding would be anti-dilutive:
|
|
|
|
|
|
|
March 31, 2007
|
|
|
|
(Unaudited)
|
|
Net (loss)
|
|
$
|
(154,373,000
|
)
|
Pro forma weighted average shares outstanding:
|
|
|
|
|
Original CVR shares of common stock
|
|
|
100
|
|
Effect of 628,667.20 to 1 stock split
|
|
|
62,866,620
|
|
Issuance of shares of common stock to management in exchange for
subsidiary shares
|
|
|
247,471
|
|
Issuance of shares of common stock to employees
|
|
|
27,100
|
|
Issuance of shares of common stock in the initial public offering
|
|
|
23,000,000
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
86,141,291
|
|
Dilutive securities issuance of non-vested shares of common stock
to board of directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
86,141,291
|
|
|
|
|
|
|
|
|
|
|
Pro forma basic loss per share
|
|
$
|
(1.79
|
)
|
Pro forma dilutive loss per share
|
|
$
|
(1.79
|
)
|
(12) Commitments and Contingent Liabilities
The minimum required payments for the Companys lease agreements and unconditional purchase
obligations are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Unconditional
|
|
|
|
Leases
|
|
|
Purchase Obligations
|
|
Nine months ending December 31, 2008
|
|
$
|
2,833
|
|
|
$
|
20,757
|
|
Year ending December 31, 2009
|
|
|
3,266
|
|
|
|
28,229
|
|
Year ending December 31, 2010
|
|
|
1,680
|
|
|
|
55,762
|
|
Year ending December 31, 2011
|
|
|
948
|
|
|
|
53,939
|
|
Year ending December 31, 2012
|
|
|
196
|
|
|
|
51,333
|
|
Thereafter
|
|
|
10
|
|
|
|
372,325
|
|
|
|
|
|
|
|
|
|
|
$
|
8,933
|
|
|
$
|
582,345
|
|
|
|
|
|
|
|
|
The Company leases various equipment and real properties under long-term operating leases. For
the three months ended March 31, 2008 and 2007, lease expense totaled $1,071,000 and $1,007,000,
respectively. The lease
20
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
agreements have various remaining terms. Some agreements are renewable,
at the Companys option, for additional periods. It is expected, in the ordinary course of
business, that leases will be renewed or replaced as they expire.
From time to time,
the Company is involved in various lawsuits arising in the normal course of
business, including matters such as those described below under Environmental, Health, and Safety
Matters. Liabilities related to such lawsuits are recognized when the related costs are probable
and can be reasonably estimated. It is possible that Managements estimates of the outcomes will
change within the next year due to uncertainties inherent in litigation and settlement
negotiations. In the opinion of management, the ultimate resolution of the Companys litigation
matters is
not expected to have a material adverse effect on the accompanying consolidated financial
statements. There can be no assurance that managements beliefs or opinions with respect to
liability for potential litigation matters are accurate.
Crude oil was discharged from the Companys refinery on July 1, 2007 due to the short amount
of time available to shut down and secure the refinery in preparation for the flood that occurred
on June 30, 2007. As a result of the crude oil discharge, two putative class action lawsuits (one
federal and one state) were filed seeking unspecified damages with class certification under
applicable law for all residents, domiciliaries and property owners of Coffeyville, Kansas who were
impacted by the oil release.
The Company filed a motion to dismiss the federal suit for lack of subject matter
jurisdiction. On November 6, 2007, the judge in the federal class action lawsuit granted the
Companys motion to dismiss for lack of subject matter jurisdiction and no appeal was taken.
With respect to the state suit, the District Court of Montgomery County, Kansas conducted an evidentiary hearing on the issue
of class certification on October 24 and 25, 2007 and ruled against the class certification leaving
only the original two plaintiffs. To date no other lawsuits have been filed as a result of flood
related damages.
As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into
an administrative order on consent (Consent Order) with the Environmental Protection Agency (EPA)
on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil
from the Companys refinery caused and may continue to cause an imminent and substantial threat to
the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform
specified remedial actions to respond to the discharge of crude oil from the Companys refinery.
The Company is currently remediating the crude oil discharge and expects its primary remedial actions to
continue through May 2008 with continuing minor activities for a period thereafter.
The Company engaged experts to assess and test the areas affected by the crude oil spill. The
Company commenced a program on July 19, 2007 to purchase approximately 330 homes and other
commercial properties in connection with the flood and the crude oil release. Total costs recorded
to date are $13.4 million, which include costs incurred in 2007 of $13.1 million and costs for the
three months ended March 31, 2008 of $0.3 million. Total costs recorded related to personal
property claims were approximately $1.7 million, which were all recorded in 2007. Total costs
recorded related to estimated commercial property to be purchased and associated claims were
approximately $3.6 million, which were all recorded in 2007. The total amount of gross costs recorded
for the three months ended March 31, 2008 related to the residential and commercial purchase and
property claims program were approximately $0.3 million. As the crude oil spill took place in the
second and third quarter of 2007, no costs associated with the spill were incurred in the first
quarter of 2007.
As of March 31, 2008, the total costs recorded for obligations other than the purchase of
homes, commercial properties and related personal property claims approximated $30.0 million.
The Company has recorded as of March 31, 2008 total costs (net of anticipated insurance recoveries
recorded of $21.4 million) associated with remediation and third party property damage claims
resolution of approximately $27.3 million. The Company has not estimated or accrued for, because
management does not believe it is probable that there will be
21
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
any potential fines, penalties or
claims that may be imposed or brought by regulatory authorities or possible additional damages
arising from class action lawsuits related to the flood.
It is difficult to estimate the ultimate cost of environmental remediation resulting from the
crude oil discharge or the cost of third party property damage that the Company will ultimately be
required to pay. The costs and damages that the Company will ultimately pay may be greater than
the amounts described and projected above. Such excess costs and damages could be material to the
consolidated financial statements.
The Company is seeking insurance coverage for this release and for the ultimate costs for
remediation, property damage claims, cleanup, resolution of class action lawsuits, and other claims
brought by regulatory authorities. Although the Company believes that it will recover substantial
sums under its environmental and liability insurance policies, the Company is not sure of the
ultimate amount or timing of such recovery because of the difficulty inherent in projecting the
ultimate resolution of the Companys claims. The difference between what the Company receives
under its insurance policies compared to what has been recorded and described above could be
material to the consolidated financial statements. The Company received $10.0 million of
insurance proceeds under its environmental insurance policy in 2007.
Environmental, Health, and Safety (EHS) Matters
CVR is subject to various stringent federal, state, and local EHS rules and regulations.
Liabilities related to EHS matters are recognized when the related costs are probable and can be
reasonably estimated. Estimates of these costs are based upon currently available facts, existing
technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS
liabilities, no offset is made for potential recoveries. Such liabilities include estimates of the
Companys share of costs attributable to potentially responsible parties which are insolvent or
otherwise unable to pay. All liabilities are monitored and adjusted regularly as new facts emerge
or changes in law or technology occur.
CVR owns and/or operates manufacturing and ancillary operations at various locations directly
related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore,
CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of
these locations.
Through an Administrative Order issued under the Resource Conservation and Recovery Act, as
amended (RCRA), CVR is a potential party responsible for conducting corrective actions at its
Coffeyville, Kansas and Phillipsburg, Kansas facilities. In 2005, CRNF agreed to participate in
the State of Kansas Voluntary Cleanup and Property Redevelopment Program (VCPRP) to address a
reported release of urea ammonium nitrate (UAN) at the Coffeyville UAN loading rack. As of March
31, 2008 and December 31, 2007, environmental accruals of $7,713,000 and $7,646,000, respectively,
were reflected in the consolidated balance sheets for probable and estimated costs for remediation
of environmental contamination under the RCRA Administrative Order and the VCPRP, including amounts
totaling $2,789,000 and $2,802,000, respectively, included in other current liabilities. The
Companys accruals were determined based on an estimate of payment costs through 2033, which scope
of remediation was arranged with the EPA and are discounted at the appropriate risk free rates at
March 31, 2008 and
December 31, 2007, respectively. The accruals include estimated closure and post-closure costs of
$1,580,000 and $1,549,000 for two landfills at March 31, 2008 and December 31, 2007, respectively.
The estimated future payments for these required obligations are as follows (in thousands):
|
|
|
|
|
|
|
Amount
|
|
Nine months ending December 31, 2008
|
|
|
2,617
|
|
Year ending December 31, 2009
|
|
|
687
|
|
Year ending December 31, 2010
|
|
|
1,556
|
|
Year ending December 31, 2011
|
|
|
313
|
|
Year ending December 31, 2012
|
|
|
313
|
|
Thereafter
|
|
|
3,282
|
|
|
|
|
|
Undiscounted total
|
|
|
8,768
|
|
Less amounts representing interest at 3.13%
|
|
|
1,055
|
|
|
|
|
|
Accrued environmental liabilities at March 31, 2008
|
|
$
|
7,713
|
|
|
|
|
|
22
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
Management periodically reviews and, as appropriate, revises its environmental accruals.
Based on current information and regulatory requirements, management believes that the accruals
established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of sulfur in diesel and gasoline.
The EPA has granted the Company a petition for a technical hardship waiver with respect to the date
for compliance in meeting the sulfur-lowering standards. CVR spent approximately $17 million in
2007, $79 million in 2006 and $27 million in 2005 to comply
with the low-sulfur rules. CVR has spent $2 million in the first three
months of 2008 and based on information currently available, anticipates spending approximately $17
million in the last nine months of 2008 and $26 million in 2009 to comply with the low-sulfur
rules. The entire amounts are expected to be capitalized.
Environmental expenditures are capitalized when such expenditures are expected to result in
future economic benefits. For the three month periods ended March 31, 2008 and 2007, capital
expenditures were $15,473,000 and $50,687,000, respectively, and were incurred to improve the
environmental compliance and efficiency of the operations.
CVR believes it is in substantial compliance with existing EHS rules and regulations. There
can be no assurance that the EHS matters described above or other EHS matters which may develop in
the future will not have a material adverse effect on the
Companys business, financial condition, or results
of operations.
(13) Derivative Financial Instruments
Loss on derivatives consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
Realized loss on swap agreements
|
|
$
|
(21,516
|
)
|
|
$
|
(8,534
|
)
|
Unrealized loss on swap agreements
|
|
|
(13,907
|
)
|
|
|
(119,704
|
)
|
Realized loss on other agreements
|
|
|
(7,993
|
)
|
|
|
(2,763
|
)
|
Unrealized gain (loss) on other agreements
|
|
|
1,157
|
|
|
|
(5,332
|
)
|
Realized gain on interest rate swap agreements
|
|
|
522
|
|
|
|
1,241
|
|
Unrealized loss on interest rate swap agreements
|
|
|
(6,134
|
)
|
|
|
(1,867
|
)
|
|
|
|
|
|
|
|
Total loss on derivatives
|
|
$
|
(47,871
|
)
|
|
$
|
(136,959
|
)
|
|
|
|
|
|
|
|
CVR is subject to price fluctuations caused by supply conditions, weather, economic
conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil
and other inventories and to fix margins on certain future production, CVR may enter into various
derivative transactions. In addition, CALLC, as further
described below, entered into certain commodity derivate contracts and an interest rate swap
as required by the long-term debt agreements.
CVR
has adopted SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities
. SFAS 133 imposes extensive record-keeping requirements in order to designate a
derivative financial instrument as a hedge. CVR holds derivative instruments, such as
exchange-traded crude oil futures, certain over-the-counter forward swap agreements and interest
rate swap agreements, which it believes provide an economic hedge on future transactions, but such
instruments are not designated as hedges. Gains or losses related to the
23
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
change in fair value and
periodic settlements of these derivative instruments are classified
as loss on derivatives, net in the
Consolidated Statements of Operations.
At March 31, 2008, CVRs Petroleum Segment held commodity derivative contracts (swap
agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see Note 15,
Related Party Transactions). The swap agreements were originally executed by CALLC on June 16,
2005 and were required under the terms of the Companys long-term debt agreements. The notional
quantities on the date of execution were 100,911,000 barrels of crude
oil, 1,889,459,250 gallons of
heating oil and 2,348,802,750 gallons of unleaded gasoline. The swap agreements were executed at
the prevailing market rate at the time of execution and management believes the swap agreements
provide an economic hedge on future transactions. At March 31, 2008 the notional open amounts
under the swap agreements were 36,190,000 barrels of crude oil, 759,990,000 gallons of heating oil
and 759,990,000 gallons of unleaded gasoline. These positions resulted in unrealized losses for
the three months ended March 31, 2008 and 2007 of $13,907,000 and $119,704,000, respectively. The
Petroleum Segment recorded $21,516,000 and $8,534,000 in realized losses on these swap agreements
for the three month periods ended March 31, 2008 and 2007, respectively.
The
Petroleum Segment also recorded mark-to-market net losses, in loss on
derivatives, net exclusive of the swap
agreements described above and the interest rate swaps described in the following paragraph, of $6,836,000 and $8,095,000, for the three month periods ended March 31, 2008
and 2007, respectively. All of the activity related to the commodity derivative contracts is
reported in the Petroleum Segment.
At March 31, 2008, CRLLC held derivative contracts known as interest rate swap agreements that
converted CRLLCs floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of
$325,000,000. Half of the agreements are held with a related party (as described in Note 15,
Related Party Transactions), and the other half are held with a financial institution that is a
lender under CRLLCs long-term debt agreements. The swap agreements carry the following terms:
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
Fixed
|
Period covered
|
|
amount
|
|
interest rate
|
June 30, 2007 to March 31, 2008
|
|
325 million
|
|
|
4.195
|
%
|
March 31, 2008 to March 30, 2009
|
|
250 million
|
|
|
4.195
|
%
|
March 31, 2009 to March 30, 2010
|
|
180 million
|
|
|
4.195
|
%
|
March 31, 2010 to June 29, 2010
|
|
110 million
|
|
|
4.195
|
%
|
CVR pays the fixed rates listed above and receives a floating rate based on three-month LIBOR
rates, with payments calculated on the notional amounts listed above. The notional amounts do
not represent actual amounts exchanged by the parties but instead represent the amounts on which
the contracts are based. The swap is settled quarterly and marked-to-market at each reporting
date, and all unrealized gains and losses are currently recognized in income. Transactions related
to the interest rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer
segments. Mark-to-market net losses on derivatives and quarterly settlements were $5,612,000 and
$626,000 for the three month periods ended March 31, 2008 and 2007, respectively.
(14) Fair Value Measurements
In
September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
. This statement established a single authoritative
definition of fair value
when accounting rules require the use of fair value, set out a framework for measuring
fair value, and required additional disclosures about fair value measurements. SFAS 157 clarifies
that fair value is an exit price, representing the amount that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between market participants.
24
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
The Company adopted SFAS 157 on January 1, 2008 with the exception of nonfinancial assets
and nonfinancial liabilities that were deferred by FASB Staff Position 157-2 as discussed in
Note 2 to the Condensed Consolidated Financial Statements. As of March 31, 2008, the Company
has not applied SFAS 157 to goodwill and intangible assets in accordance with FASB Staff Position
157-2.
SFAS 157 discusses valuation techniques, such as the market approach (prices and other
relevant information generated by market conditions involving identical or comparable assets or
liabilities), the income approach (techniques to convert future amounts to single present
amounts based on market expectations including present value techniques and option-pricing), and
the cost approach (amount that would be required to replace the service capacity of an asset
which is often referred to as replacement cost). SFAS 157 utilizes a fair value hierarchy
that prioritizes the inputs to valuation techniques used to measure fair value into three broad
levels. The following is a brief description of those three levels:
|
|
|
Level 1 Quoted prices in active market for identical assets and liabilities
|
|
|
|
|
Level 2 Other significant observable inputs (including quoted prices in active markets
for similar assets or liabilities)
|
|
|
|
|
Level 3 Significant unobservable inputs (including the Companys own assumptions in
determining the fair value)
|
The following table sets forth the assets and liabilities measured at fair value on a recurring
basis, by input level, as of March 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Cash Flow Swap
|
|
|
|
|
|
$
|
(13,907
|
)
|
|
|
|
|
|
$
|
(13,907
|
)
|
Interest Rate Swap
|
|
|
|
|
|
|
(6,134
|
)
|
|
|
|
|
|
|
(6,134
|
)
|
Other Derivative Agreements
|
|
|
|
|
|
|
1,157
|
|
|
|
|
|
|
|
1,157
|
|
The Companys derivative contracts giving rise to assets or liabilities under Level 2 are valued
using pricing models based on other significant observable inputs.
(15) Related Party Transactions
GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates
VII, L.P. and related entity (Kelso) are majority owners of CVR.
On
June 24, 2005, CALLC entered into management services agreements with each of GS and Kelso
pursuant to which GS and Kelso agreed to provide CALLC with managerial and advisory services. In
consideration for these services, an annual fee of $1.0 million
was paid to each of GS and Kelso, plus
reimbursement for any out-of-pocket expenses. The agreements terminated upon consummation of CVRs
initial public offering on October 26, 2007.
Relating to the agreements, $0 and $538,000 were expensed in selling, general, and
administrative expenses (exclusive of depreciation and amortization) for the three months ended
March 31, 2008 and March 31, 2007, respectively. The Company paid a one-time fee of $5.0 million
to each of GS and Kelso by reason of the termination of the
agreements on October 26, 2007.
CALLC entered into certain crude oil, heating oil and gasoline swap agreements with a
subsidiary of GS. Additional swap agreements with this subsidiary of GS were entered into on June
16, 2005, with an expiration date of June 30, 2010 (as described in Note 13, Derivative Financial
Instruments). These agreements were assigned to Coffeyville Resources LLC, a subsidiary of CVR.
Losses totaling $35,423,000 and $128,238,000 were recognized
related to these swap agreements for the three months ended March 31, 2008 and 2007,
respectively, and are
25
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
reflected
in loss on derivatives, net in the Consolidated Statements of
Operations. In addition, the Consolidated Balance Sheet at March 31, 2008 and December 31, 2007
includes liabilities of $294,984,000 and $262,415,000, respectively, included in current payable to swap
counterparty and $76,411,000 and $88,230,000, respectively, included in long-term payable to swap counterparty.
On June 26, 2007, the Company entered into a letter agreement with the subsidiary of GS to
defer a $45.0 million payment owed on July 8, 2007 to the GS subsidiary for the period ended
September 30, 2007 until August 7, 2007. Interest accrued on the deferred amount of $45.0 million
at the rate of LIBOR plus 3.25%.
As a result of the flood and the related temporary cessation of business operations, the
Company entered into a subsequent letter agreement on July 11, 2007 in which the GS subsidiary
agreed to defer an additional $43.7 million of the balance owed for the period ending June 30,
2007. This deferral was entered into on the conditions that each of GS and Kelso agreed to
guarantee one half of the payment and that interest accrued on the $43.7 million from July 9, 2007
to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter agreement in which the GS subsidiary
agreed to defer to September 7, 2007 both the $45.0 million payment due August 7, 2007 along with
accrued interest and the $43.7 million payment due July 25, 2007 with the related accrued interest.
These payments were deferred on the conditions that GS and Kelso each agreed to guarantee one half
of the payments. Additionally, interest accrues on the amount from July 26, 2007 to the date of
payment at the rate of LIBOR plus 1.50%.
On August 23, 2007, the Company entered into an additional letter agreement in which the GS
subsidiary agreed to further defer both deferred payment amounts and the related accrued interest
with payment being due on January 31, 2008. Additionally, it was further agreed that the $35
million payment to settle hedged volumes through August 15, 2007 would be deferred with payment
being due on January 31, 2008. Interest accrues on all deferral amounts through the payment due
date at LIBOR plus 1.50%. GS and Kelso have each agreed to guarantee one half of all payment
deferrals. The GS subsidiary further agreed to defer these payment amounts to August 31, 2008 if
the Company closed an initial public offering prior to January 31, 2008. Due to the consummation
of the initial public offering on October 26, 2007, these payment amounts are now deferred until
August 31, 2008; however, the company is required to use 37.5% of its consolidated excess cash flow
for any quarter after January 31, 2008 to prepay the deferral amounts. As of March 31, 2008 the
Company was not required to pay any portion of the deferred amount.
These deferred
payment amounts are included in the Consolidated Balance Sheet at March 31,
2008 in current payable to swap counterparty. The deferred balance
owed to GS, excluding accrued interest payable, totalled
$123.7 million at March 31, 2008.
Approximately $4,874,000 of accrued interest payable related to the deferred payments is
included in other current liabilities at March 31, 2008.
On June 30, 2005, CALLC entered into three interest-rate swap agreements with the same
subsidiary of GS (as described in Note 13, Derivative Financial Instruments). Losses totaling
$2,813,000 and $313,000 were recognized related to these swap agreements for the three months ended
March 31, 2008 and 2007, respectively, and are reflected in loss
on derivatives, net in the Consolidated
Statements of Operations. In addition, the Consolidated Balance Sheet at March 31, 2008 and
December 31, 2007 includes $1,778,000 and $371,000, respectively, in other current liabilities and $2,223,000 and
$557,000, respectively, in other long-term liabilities related to the same agreements.
Effective December 30, 2005, the Company entered into a crude oil supply agreement with a
subsidiary of GS (Supplier). Under the agreement, the parties agreed
to negotiate the cost of each
barrel of crude oil to be purchased from a third party, and CVR
agreed to pay Supplier a fixed supply
service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is
adjusted further using a spread adjustment calculation based on the time period the crude oil is
estimated to be delivered to the refinery, other market conditions, and other factors deemed
appropriate. The initial term of the agreement was to December 31, 2006. CVR and
Supplier agreed to extend
26
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
the term
of the supply agreement for an additional 12 month period,
from January 1, 2007 through December 31, 2007, and in connection with the extension amended certain
terms and conditions of the supply agreement. On December 31, 2007, CVR and supplier entered into
an amended and restated crude oil supply agreement. The terms of the agreement remained
substantially the same. $241,000 and $360,000 were recorded on the consolidated balance
sheet at March 31, 2008 and December 31, 2007, respectively, in prepaid expenses and other
current assets for prepayment of crude oil. In addition, $62,039,000 and $43,773,000 were recorded
in inventory and $27,909,000 and $42,666,000 were recorded in accounts payable at March 31, 2008
and December 31, 2007, respectively. Expenses associated with this agreement, included in cost of
product sold (exclusive of depreciation and amortization) for the three month period ended March
31, 2008 and 2007 totaled $766,213,000 and $176,307,000, respectively. Interest expense associated
with this agreement for the three month period ended March 31, 2008 and 2007 totaled $14,000 and
$(1,029,000), respectively.
As a result of the refinery turnaround in early 2007, CVR needed to delay the processing of
quantities of crude oil that it purchased from various small independent producers. In order to
facilitate this anticipated delay, CVR entered into a purchase, storage and sale agreement for
gathered crude oil, dated March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant to the terms
of the agreement, J. Aron agreed to purchase gathered crude oil from CVR, store the gathered crude
oil and sell CVR the gathered crude oil on a forward basis.
(16) 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 coke supply agreement that became effective October
24, 2007, is based on the lesser of a coke price derived from the priced received by the fertilizer
segment for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet
coke. Prior to October 25, 2007 intercompany sales were based upon a price of $15 per ton. The
intercompany transactions are eliminated in the Other Segment. Intercompany sales included in
petroleum net sales were $2,806,000 and $580,000 for the three months ended March 31, 2008 and
2007, respectively.
Intercompany
cost of product sold (exclusive of depreciation and amortization) for
the hydrogen sales described below under
Nitrogen Fertilizer was $5,291,000 and $2,829,000 for
the three months ended March 31, 2008 and 2007, respectively.
Nitrogen Fertilizer
The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer.
Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke
transfer described above was $2,545,000 and $850,000 for the three months ended March 31, 2008 and
2007, respectively.
Beginning in 2008, the Nitrogen Fertilizer Segment made a change as to the classification of
intercompany hydrogen sales to the Petroleum Segment. In 2008, these amounts are reflected as Net
Sales for the fertilizer plant. Prior to 2008, the Nitrogen Fertilizer Segment reflected these
transactions as a reduction of cost of product sold (exclusive of deprecation and amortization).
For the quarters ended March 31, 2008 and 2007, the net sales generated from intercompany hydrogen
sales were $5,291,000 and $2,829,000, respectively. As noted above, the net sales of $2,829,000
were included as a reduction to the cost of product sold (exclusive of depreciation and
amortization) for 2007. As these intercompany sales are eliminated, there is no financial
statement impact on the consolidated financial statements.
27
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
Other Segment
The Other Segment reflects intercompany eliminations, cash and cash equivalents, all debt
related activities, income tax activities and other corporate activities that are not allocated to
the operating segments.
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
(in thousands)
|
|
|
|
2008
|
|
|
2007
|
|
Net sales
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,168,500
|
|
|
$
|
352,488
|
|
Nitrogen Fertilizer
|
|
|
62,600
|
|
|
|
38,575
|
|
Intersegment eliminations
|
|
|
(8,097
|
)
|
|
|
(580
|
)
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,223,003
|
|
|
$
|
390,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sold (exclusive of
depreciation and amortization)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,035,085
|
|
|
$
|
298,460
|
|
Nitrogen Fertilizer
|
|
|
8,945
|
|
|
|
6,060
|
|
Intersegment eliminations
|
|
|
(7,836
|
)
|
|
|
(850
|
)
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,036,194
|
|
|
$
|
303,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses (exclusive of
depreciation and amortization)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
40,290
|
|
|
$
|
96,674
|
|
Nitrogen Fertilizer
|
|
|
20,266
|
|
|
|
16,738
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
60,556
|
|
|
$
|
113,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net costs associated with flood
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
5,533
|
|
|
$
|
|
|
Nitrogen Fertilizer
|
|
|
(17
|
)
|
|
|
|
|
Other
|
|
|
247
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,763
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
14,877
|
|
|
$
|
9,794
|
|
Nitrogen Fertilizer
|
|
|
4,477
|
|
|
|
4,394
|
|
Other
|
|
|
281
|
|
|
|
47
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
19,635
|
|
|
$
|
14,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
63,618
|
|
|
$
|
(63,468
|
)
|
Nitrogen Fertilizer
|
|
|
26,017
|
|
|
|
9,319
|
|
Other
|
|
|
(2,277
|
)
|
|
|
165
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
87,358
|
|
|
$
|
(53,984
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
22,541
|
|
|
$
|
106,501
|
|
Nitrogen Fertilizer
|
|
|
2,817
|
|
|
|
402
|
|
Other
|
|
|
798
|
|
|
|
460
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
26,156
|
|
|
$
|
107,363
|
|
|
|
|
|
|
|
|
28
CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months
Ended
March 31,
2008
|
|
|
Year
Ended
December 31,
2007
|
|
Total assets
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
1,352,961
|
|
|
$
|
1,277,124
|
|
Nitrogen Fertilizer
|
|
|
496,326
|
|
|
|
446,763
|
|
Other
|
|
|
74,304
|
|
|
|
144,469
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,923,591
|
|
|
$
|
1,868,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
|
|
Petroleum
|
|
$
|
42,806
|
|
|
$
|
42,806
|
|
Nitrogen Fertilizer
|
|
|
40,969
|
|
|
|
40,969
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
83,775
|
|
|
$
|
83,775
|
|
|
|
|
|
|
|
|
29
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 three month period ended March 31, 2008 (Form 10-Q) as well as the Companys Annual Report on Form 10-K/A for the year ended
December 31, 2007. Results of operations for the three month period ended March 31, 2008 are not
necessarily indicative of results to be attained for any other period.
Forward-Looking Statements
This Form 10-Q, including this Managements Discussion and Analysis of Financial Condition and
Results of Operations, contains forward-looking statements as defined by the SEC. Such
statements are those concerning contemplated transactions and strategic plans, expectations and
objectives for future operations. These include, without limitation:
|
|
|
statements, other than statements of historical fact, that address activities,
events or developments that we expect, believe or anticipate will or may occur in the
future;
|
|
|
|
|
statements relating to future financial performance, future capital sources and
other matters; and
|
|
|
|
|
any other statements preceded by, followed by or that include the words
anticipates, believes, expects, plans, intends, estimates, projects,
could, should, may, or similar expressions.
|
Although we believe that our plans, intentions and expectations reflected in or suggested by
the forward-looking statements we make in this Form 10-Q, including this Managements Discussion
and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations
will be achieved. These statements are based on assumptions made by us based on our experience and
perception of historical trends, current conditions, expected future developments and other factors
that we believe are appropriate in the circumstances. Such statements are subject to a number of
risks and uncertainties, many of which are beyond our control. You are cautioned that any such
statements are not guarantees of future performance and actual results or developments may differ
materially from those projected in the forward-looking statements as a result of various factors,
including but not limited to those set forth under Risk Factors in our Annual Report on Form
10-K/A for the year ended December 31, 2007 and contained elsewhere in this Form 10-Q.
All forward-looking statements contained in this Form 10-Q only speak as of the date of this
document. We undertake no obligation to update or revise publicly any forward-looking statements
to reflect events or circumstances that occur after the date of this Form 10-Q, or to reflect the
occurrence of unanticipated events.
Company Overview
We are an independent refiner and marketer of high value transportation fuels. In addition, we
currently own all of the interests (other than the managing general partner interest and associated
IDRs) in a limited partnership which produces the nitrogen fertilizers ammonia and UAN. At current
natural gas and pet coke prices, the nitrogen fertilizer business is the lowest cost producer and
marketer of ammonia and UAN in North America.
We operate under two business segments: petroleum and nitrogen fertilizer. Our petroleum
business includes a 113,500 bpd complex full coking medium sour crude refinery in Coffeyville, Kansas. In
addition, supporting businesses include (1) a crude oil gathering system serving central Kansas,
northern Oklahoma, and southwest Nebraska, (2) storage and terminal facilities for asphalt and
refined fuels in Phillipsburg, Kansas, and (3) a rack marketing division supplying product through
tanker trucks directly to customers located in close geographic proximity to Coffeyville and
Phillipsburg and at throughput terminals on Magellan Midstream Partners L.P.s (Magellan) refined products
distribution systems. In addition to rack sales (sales which are made at terminals into third
party tanker trucks), we make bulk sales (sales through third party pipelines) into the
mid-continent markets via Magellan and into Colorado and other destinations utilizing the product
pipeline networks owned by Magellan, Enterprise Products Partners L.P. and NuStar Energy L.P. Our
refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil
trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from
locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude
variety in the world capable of being transported by pipeline.
30
The nitrogen fertilizer segment consists of our interest in CVR Partners, LP, a limited
partnership controlled by our affiliates, which operates a nitrogen fertilizer plant and the
nitrogen fertilizer business. The nitrogen fertilizer business is the lowest cost producer and
marketer of ammonia and UAN in North America, at current natural gas and pet coke prices. The
fertilizer plant is the only commercial facility in North America utilizing a coke gasification
process to produce nitrogen fertilizers. The use of low cost by-product pet coke from the
adjacent oil refinery as feedstock (rather than natural gas) to produce hydrogen provides the
facility with a significant competitive advantage given the currently high and volatile natural gas prices.
The plants competition utilizes natural gas to produce ammonia.
CVR Energys Initial Public Offering
On October 26, 2007 we completed an initial public offering of 23,000,000 shares of our common
stock. The initial public offering price was $19.00 per share. The net proceeds to us from the
sale of our common stock were approximately $408.5 million, after deducting underwriting discounts
and commissions. We also incurred approximately $11.4 million of other costs related to the
initial public offering.
The
net proceeds from the offering were used to repay $280.0 million of CVRs outstanding term
loan debt and to repay in full our $25 million secured credit facility and $25.0 million
unsecured credit facility. We also repaid $50.0 million of indebtedness under our revolving credit
facility.
In connection with the initial public offering, we also became the indirect owner of
Coffeyville Resources, LLC and all of its refinery assets. This was accomplished by CVR issuing
62,866,720 shares of its common stock to certain entities controlled by its majority stockholders pursuant to a stock split in exchange for the interests in certain subsidiaries of CALLC. Immediately following the
completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding
restricted shares issued.
CVR Partners Proposed Initial Public Offering
On February 28, 2008, the Partnership filed a registration statement with the SEC to effect an
initial public offering of 5,250,000 common units representing limited partner interests. The
Partnership intends to apply to the NYSE to list its common units. If the Partnerships initial
public offering is consummated on the proposed terms, the 30,303,000 special GP units and 30,333
special LP units which we indirectly own will convert into 18,750,000 GP units and 16,000,000
subordinated GP units of the Partnership, and as a result, we will indirectly own approximately
87% of the outstanding units of the Partnership. The registration statement also provides that the
net proceeds from the Partnerships initial public offering will be used to reimburse Coffeyville
Resources for certain capital expenditures made on the Partnerships behalf prior to October 24,
2007 (approximately $18.4 million) and to pay financing fees in connection with entering into a new
revolving credit facility (approximately $2.5 million) with the remainder to be retained by the
Partnership to fund working capital and future capital expenditures of its business, including the
ongoing expansion of the nitrogen fertilizer plant (approximately $85 million). There can be no
assurance that any such offering will be consummated on the terms described in the registration
statement or at all.
Major Influences on Results of Operations
Petroleum Business.
Our earnings and cash flows from our petroleum operations are primarily
affected by the relationship between refined product prices and the prices for crude oil and other
feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are
processed and blended into refined products. The cost to acquire feedstocks and the price for
which refined products are ultimately sold depend on factors beyond our control, including the
supply of, and demand for, crude oil, as well as gasoline and other refined products which, in
turn, depend on, among other factors, changes in domestic and foreign economies, weather
conditions, domestic and foreign political affairs, production levels, the availability of imports,
the marketing of competitive fuels and the extent of government regulation. Because we apply
first-in, first-out, or FIFO, accounting to value our inventory, crude oil price movements may
impact net income in the short term because of instantaneous changes in the value of the minimally
required, unhedged on hand inventory. The effect of changes in crude oil prices on our results of
operations is influenced by the rate at which the prices of refined products adjust to reflect
these changes.
31
Feedstock and refined product prices are also affected by other factors, such as product
pipeline capacity, local market conditions and the operating levels of competing refineries. Crude
oil costs and the prices of refined products have, historically, been
subject to wide fluctuations. An expansion or upgrade of our competitors
facilities, price volatility, international political and economic developments and other
factors beyond our control are likely to continue to play an important role in refining industry
economics. These factors can impact, among other things, the level of inventories in the market,
resulting in price volatility and reduction in product margins. Moreover, the refining industry
typically experiences seasonal fluctuations in demand for refined products, such as increases in
the demand for gasoline during the summer driving season and for home heating oil during the
winter, primarily in the Northeast.
Crude oil costs are at historic highs. West Texas Intermediate crude
oil, or WTI crude oil, which is used as a benchmark for other crude
oils, averaged $97.82 per barrel for the three months ended
March 31, 2008, as compared to $58.27 per barrel during the comparable period in 2007. WTI crude oil prices averaged over
$105 per barrel in March 2008 and had spiked to over $126 per barrel as of May 13, 2008.
In order to assess our operating performance, we compare our net sales, less cost of product
sold (refining margin), against an industry refining margin benchmark. The industry refining
margin is calculated by assuming that two barrels of benchmark light sweet crude oil is converted
into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred
to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of
New York Mercantile Exchange (NYMEX) gasoline and heating oil against the market value of NYMEX WTI
(WTI) crude oil, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack
spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per
barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark
production of gasoline and distillate. The 2-1-1 crack spreads were significantly weaker in the first quarter of 2008 when compared to the first quarter of 2007.
As a percentage of crude oil prices, the 2-1-1 crack spread was approximately 21% in the first quarter of 2007 but only 12% in the first quarter of 2008.
Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery
has certain feedstock costs and/or logistical advantages as compared to a benchmark refinery and
our product yield is less than total refinery throughput, the crack spread does not account for all
the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that
includes quantities of heavy and medium sour crude oil that has historically cost less than WTI
crude oil. We measure the cost advantage of our crude oil slate by calculating the spread between
the price of our delivered crude oil to the price of WTI crude oil, a light sweet crude oil. The
spread is referred to as our consumed crude differential. Our refinery margin can be impacted
significantly by the consumed crude differential. Our consumed crude differential will move
directionally with changes in the West Texas Sour
(WTS) differential to WTI and the West Canadian Select (WCS) differential to WTI as both these differentials indicate the relative price of heavier, more sour,
slate to WTI. The WCS-WTI differential for the first quarter of 2008
was $19.84 a barrel as compared to $14.80 a barrel in the first
quarter of 2007. The differential for the fourth quarter of 2007 was
$32.60 a barrel. This differential is now widening, in a contra-seasonal manner, which we can benefit from in terms of our weighted crude oil costs.
The correlation between our consumed crude differential and published differentials
will vary depending on the volume of light medium sour crude and heavy sour crude we purchase as a
percent of our total crude volume and will correlate more closely with such published differentials
the heavier and more sour the crude oil slate.
We produce a high volume of high value products, such as gasoline and distillates. Approximately 39% of our product slate is ultra low sulfur diesel
, which provides us with tax credits and is currently selling at higher margins than gasoline (which represents 48% of our refined products).
The balance of our production is devoted to other products, including
the petroleum coke used by the nitrogen fertilizer business. We benefit
from the fact that our marketing region consumes more refined products than it produces so that the
market prices of our products have to be high enough to cover the logistics cost for the U.S. Gulf
Coast refineries to ship into our region. The result of this logistical advantage and the fact the
actual product specification used to determine the NYMEX is different from the actual production in
the refinery is that prices we realize are different than those used in determining the 2-1-1 crack
spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is
referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and heating oil PADD
II, Group 3 vs. NYMEX basis, or heating oil basis.
Our direct operating expense structure is also important to our profitability. Major direct
operating expenses include energy, employee labor, maintenance, contract labor, and environmental
compliance. Our predominant variable cost is energy which is comprised primarily of electrical
cost and natural gas. We are therefore sensitive to the movements of natural gas prices.
Consistent, safe, and reliable operations at our refinery are key to our financial performance
and results of operations. Unplanned downtime at our refinery may result in lost margin
opportunity, increased maintenance expense and a temporary increase in working capital investment
and related inventory position.
Nitrogen Fertilizer Business.
In the nitrogen fertilizer business, earnings and cash flow
from operations are primarily affected by the relationship between nitrogen fertilizer product
prices and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business
uses minimal natural gas as feedstock and, as a result, is not directly impacted in terms of cost
by high or volatile swings in natural gas prices. Instead, our adjacent oil refinery supplies the
majority of the pet coke feedstock needed by the nitrogen fertilizer business. The price at which
32
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 the low, high natural gas
prices do not force the nitrogen fertilizer business to shut down its operations because it
employs pet coke as a feedstock to produce ammonia and UAN rather than natural gas.
Nitrogen fertilizer prices are also affected by other factors, such as local market conditions
and the operating levels of competing facilities. Natural gas costs and the price of nitrogen
fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade
of competitors facilities, price volatility, international political and economic developments and
other factors are likely to continue to play an important role in nitrogen fertilizer industry
economics. These factors can impact, among other things, the level of inventories in the market,
resulting in price volatility and a reduction in product margins. Moreover, the industry typically
experiences seasonal fluctuations in demand for nitrogen fertilizer products.
The demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer
application rate decisions of individual farmers. Individual farmers make planting decisions based
largely on the prospective profitability of a harvest, while the specific varieties and amounts of
fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions,
weather patterns and the types of crops planted.
The value of nitrogen fertilizer products is also an important consideration in understanding
our results. The nitrogen fertilizer business generally upgrades approximately two-thirds of its
ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN
production is a major contributor to our profitability. In order to assess the value of nitrogen
fertilizer products, we calculate netbacks, also referred to as plant gate price. Netbacks refer
to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding
shipment costs.
Prices
for both ammonia and UAN for the quarter ended March 31, 2008
reflect strong current demand for these products. Ammonia plant gate
prices averaged $494 per ton for the quarter ended March 31,
2008, compared to $347 per ton during the comparable period in 2007.
UAN prices averaged $262 per ton for the quarter ended
March 31, 2008, compared to $169 per ton during the comparable
2007 period.
The direct operating expense structure of the nitrogen fertilizer business is also important
to its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has
significantly higher fixed costs than natural gas-based fertilizer plants. Major direct operating
expenses include electrical energy, employee labor, maintenance, including contract labor, and
outside services. These costs comprise the fixed costs associated with the fertilizer plant.
Factors Affecting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable with
prior periods or to our results of operations in the future for the reasons discussed below.
2007 Flood and Crude Oil Discharge
During the weekend of June 30, 2007, torrential rains in southeast Kansas caused the Verdigris
River to overflow its banks and flood the town of Coffeyville. Our refinery and nitrogen
fertilizer plant, which are located in close proximity to the Verdigris River, were severely
flooded, sustained major damage and required repairs.
As a result of the flooding, our refinery and nitrogen fertilizer facilities stopped operating
on June 30, 2007. The refinery started operating its reformer on August 6, 2007 and began to
charge crude oil to the facility on August 9, 2007. Substantially all of the refinerys units were
in operation by August 20, 2007. The nitrogen fertilizer facility, situated on slightly higher
ground, sustained less damage than the refinery. The nitrogen fertilizer facility initiated
startup at its production facility on July 13, 2007.
Total gross costs incurred and recorded as of March 31, 2008 related to the third party costs to repair the refinery and fertilizer facilities were
approximately $82.5 million and $4.0 million, respectively. In addition, we currently estimate that
approximately $2.1 million in third party costs related to the repair of flood damaged property
will be recorded in future periods.
33
In addition, despite our efforts to secure the refinery prior to its evacuation as a result of
the flood, we estimate that 1,919 barrels (80,600 gallons) of crude oil and 226 barrels of crude
oil fractions were discharged from our refinery into the Verdigris River flood waters beginning on
or about July 1, 2007. We are currently remediating the contamination caused by the crude oil
discharge. Total net costs recorded as of March 31, 2008 associated with remediation efforts and third party property
damage incurred by the crude oil discharge are approximately $27.3 million. This amount is net of
anticipated insurance recoveries of $21.4 million. In 2007, the Company had received insurance
proceeds of $10.0 million under its property insurance policy,
and $10.0 million under its
environmental policies related to recovery of certain costs associated with the crude oil
discharge.
Our results for the three months ended March 31, 2008 include pretax costs of $5.8 million
associated with the flood and related crude oil discharge. This amount is net of anticipated
insurance recoveries for the three months ended March 31, 2008 of $1.8 million. In the first
quarter of 2008, the Company received $1.5 million under the Builders Risk Insurance Policy.
Below
is a summary of the gross cost arising from the flood and crude oil
discharge and a reconciliation of the related insurance
receivable (in millions):
|
|
|
|
|
|
|
|
|
|
|
Total
Costs
|
|
For the Three Months
Ended
March 31, 2008
|
Total gross
costs incurred
|
|
$
|
154.5
|
|
|
$
|
7.6
|
|
Total
insurance receivable
|
|
|
(107.2
|
)
|
|
|
(1.8
|
)
|
|
|
|
|
|
|
|
Net costs
associated with the flood
|
|
$
|
47.3
|
|
|
$
|
5.8
|
|
|
|
|
|
|
|
|
Receivable
Reconciliation
|
Total
insurance receivable
|
|
$
|
107.2
|
|
Less
insurance proceeds received
|
|
|
(21.5
|
)
|
|
|
|
|
Insurance
receivable
|
|
$
|
85.7
|
|
Refinancing and Prior Indebtedness
At
December 31, 2006, we had a balance of $775.0 million on our term loan facility. In
October 2007, we paid down $280.0 million of outstanding long-term debt with initial public offering
proceeds. In addition, proceeds of our initial public offering were used to repay in full our $25.0 million secured credit facility,
our $25.0 million unsecured credit facility and $50.0 million of indebtedness under our revolving credit
facility. Our Statements of Operations for the three months ended March 31, 2008 includes interest
expense of $11.3 million on the term debt of $488.0 million. Interest expense associated with the
term debt for the three months ended March 31, 2007 totaled $11.9 million. Term debt as of March
31, 2007 totaled $775.0 million.
J. Aron Deferrals
As a result of the flood and the temporary cessation of our operations on June 30, 2007,
Coffeyville Resources, LLC entered into several deferral agreements with J. Aron & Company (J.
Aron) with respect to the Cash Flow Swap, which is a series of commodity derivative arrangements
whereby if crack spreads fall below a fixed level, J. Aron agreed to pay the difference to us, and
if crack spreads rise above a fixed level, we agreed to pay the difference to J. Aron. These
deferral agreements deferred to August 31, 2008 the payment of approximately $123.7 million (plus
accrued interest) which we owed to J. Aron. We are required to use 37.5% of our consolidated
excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts. As of
March 31, 2008 we were not required to repay any portion of the deferred amount.
Change in Reporting Entity as a Result of the Initial Public Offering
Prior to our initial public offering in October 2007, our operations were conducted by an
operating partnership, Coffeyville Resources, LLC. The reporting entity of the organization was
also a partnership. Immediately prior to the closing of our initial public offering, Coffeyville
Resources, LLC became an indirect, wholly-owned subsidiary of CVR Energy, Inc. As a result, for
periods ending after October 2007, we report our results of operations and financial condition as a
corporation on a consolidated basis rather than as an operating partnership.
34
2007 Turnaround
In
April 2007, we completed a planned turnaround of our refining plant at a total cost
approximating $80.4 million, which included $66.0 million
recorded in the first quarter of
2007. The refinery processed crude until February 11, 2007 at which time a staged shutdown of the
refinery began. The refinery recommenced operations on March 22, 2007 and continually increased
crude oil charge rates until all of the key units were restarted by April 23, 2007. The turnaround
significantly impacted our financial results for 2007 and had no
impact on our 2008 results.
Consolidation of Nitrogen Fertilizer Limited Partnership
Prior to the consummation of our initial public offering, we transferred our nitrogen
fertilizer business to the Partnership and sold the managing general partner interest in the
Partnership to a new entity owned by our controlling stockholders and
senior management. As of
March 31, 2008, we own all of the interests in the Partnership (other than the managing general
partner interest and associated IDRs) and are entitled to all cash that is distributed by the
Partnership. The Partnership is operated by our senior management pursuant to a services
agreement among us, the managing general partner and the Partnership. The Partnership is
managed by the managing general partner and, to the extent described below, us, as special general
partner. As special general partner of the Partnership, we have joint
management rights regarding
the appointment, termination and compensation of the chief executive officer and chief financial
officer of the managing general partner, have the right to designate two members to the board of
directors of the managing general partner and have joint management rights regarding specified
major business decisions relating to the Partnership.
We consolidate the Partnership for financial reporting purposes. We have determined that
following the sale of the managing general partner interest to an entity owned by our controlling
stockholders and senior management, the Partnership is a variable interest entity (VIE) under the
provisions of FASB Interpretation No. 46R
Consolidation of Variable Interest Entities
(FIN 46R).
Using criteria in FIN 46R, management has determined that we are the primary beneficiary of
the Partnership, although 100% of the managing general partner interest is owned by a new entity
owned by our controlling stockholders and senior management outside our reporting structure. Since
we are the primary beneficiary, the financial statements of the Partnership remain consolidated in
our financial statements. The managing general partners interest is reflected as a minority
interest on our balance sheet.
The conclusion that we are the primary beneficiary of the Partnership and required to
consolidate the Partnership as a variable interest entity is based upon the fact that substantially
all of the expected losses are absorbed by the special general partner, which we own. Additionally,
substantially all of the equity investment at risk was contributed on behalf of the special general
partner, with nominal amounts contributed by the managing general partner. The special general
partner is also expected to receive the majority, if not substantially all, of the expected returns
of the Partnership through the Partnerships cash distribution provisions.
We will need to reassess from time to time whether we remain the primary beneficiary of the
Partnership in order to determine if consolidation of the Partnership remains appropriate on a
going forward basis. Should we determine that we are no longer the primary beneficiary of the
Partnership, we will be required to deconsolidate the Partnership in our financial statements for
accounting purposes on a going forward basis. In that event, we would be required to account for
our investment in the Partnership under the equity method of accounting, which would affect our
reported amounts of consolidated revenues, expenses and other income statement items.
The principal events that would require the reassessment of our accounting treatment related to our
interest in the Partnership include:
|
|
|
a sale of some or all of our partnership interests to an unrelated party;
|
|
|
|
|
a sale of the managing general partner interest to a third party;
|
|
|
|
|
the issuance by the Partnership of partnership interests to parties other than us or our
related parties; and
|
|
|
|
|
the acquisition by us of additional partnership interests (either new interests issued
by the Partnership or interests acquired from unrelated interest holders).
|
35
In addition, we would need to reassess our consolidation of the Partnership if the Partnerships
governing documents or contractual arrangements are changed in a manner that reallocates between us
and other unrelated parties either (1) the obligation to absorb the expected losses of the
Partnership or (2) the right to receive the expected residual returns of the Partnership.
36
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, 2008 and 2007. The summary financial
data for our two operating segments does not include certain SG&A expenses and depreciation and
amortization related to our corporate offices. The following data should be read in conjunction
with our condensed consolidated financial statements and the notes thereto included elsewhere in
this Form 10-Q. All information in Managements Discussion and Analysis of Financial Condition
and Results of Operations, except for the balance sheet data as of December 31, 2007, is
unaudited.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in millions, except as otherwise
|
|
|
|
indicated)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Consolidated Statement of Operations Data:
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
1,223.0
|
|
|
$
|
390.5
|
|
Cost of product sold (exclusive of depreciation
and amortization)
|
|
|
1,036.2
|
|
|
|
303.7
|
|
Direct
operating expenses (exclusive of
depreciation and amortization)
|
|
|
60.6
|
|
|
|
113.4
|
|
Selling,
general and administrative expenses
(exclusive of depreciation and amortization)
|
|
|
13.4
|
|
|
|
13.2
|
|
Net costs associated with flood
|
|
|
5.8
|
|
|
|
|
|
Depreciation and amortization (1)
|
|
|
19.6
|
|
|
|
14.2
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
87.4
|
|
|
$
|
(54.0
|
)
|
Other income, net
|
|
|
0.9
|
|
|
|
0.5
|
|
Interest expense and other financing costs
|
|
|
(11.3
|
)
|
|
|
(11.9
|
)
|
Loss on
derivatives, net
|
|
|
(47.9
|
)
|
|
|
(137.0
|
)
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority
interest in subsidiaries
|
|
$
|
29.1
|
|
|
$
|
(202.4
|
)
|
Income tax (expense) benefit
|
|
|
(6.9
|
)
|
|
|
47.3
|
|
Minority interest in (income) loss of subsidiaries
|
|
|
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
Net income (loss) (2)
|
|
$
|
22.2
|
|
|
$
|
(154.4
|
)
|
Earnings per share, basic
|
|
$
|
0.26
|
|
|
|
|
|
Earnings per share, diluted
|
|
$
|
0.26
|
|
|
|
|
|
Weighted average shares, basic
|
|
|
86,141,291
|
|
|
|
|
|
Weighted average shares, diluted
|
|
|
86,158,791
|
|
|
|
|
|
Pro forma loss per share, basic
|
|
|
|
|
|
$
|
(1.79
|
)
|
Pro forma loss per share, diluted
|
|
|
|
|
|
$
|
(1.79
|
)
|
Pro forma weighted average shares, basic
|
|
|
|
|
|
|
86,141,291
|
|
Pro forma weighted average shares, diluted
|
|
|
|
|
|
|
86,141,291
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31,
|
|
As of December 31,
|
|
|
2008
|
|
2007
|
|
|
(in millions, except as otherwise
|
|
|
indicated)
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
25.2
|
|
|
$
|
30.5
|
|
Working capital
|
|
|
21.5
|
|
|
|
10.7
|
|
Total assets
|
|
|
1,923.6
|
|
|
|
1,868.4
|
|
Total debt, including current portion
|
|
|
499.2
|
|
|
|
500.8
|
|
Minority interest in subsidiaries
|
|
|
10.6
|
|
|
|
10.6
|
|
Stockholders equity
|
|
|
455.1
|
|
|
|
432.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in millions)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
19.6
|
|
|
$
|
14.2
|
|
Net income (loss) adjusted for unrealized gain or
loss from Cash Flow Swap (3)
|
|
|
30.6
|
|
|
|
(82.4
|
)
|
Cash flows provided by operating activities
|
|
|
24.2
|
|
|
|
44.1
|
|
Cash flows (used in) investing activities
|
|
|
(26.2
|
)
|
|
|
(107.4
|
)
|
Cash flows (used in) provided by financing
activities
|
|
|
(3.4
|
)
|
|
|
29.0
|
|
Capital expenditures for property, plant and
equipment
|
|
|
26.2
|
|
|
|
107.4
|
|
37
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Ended March 31,
|
|
|
2008
|
|
2007
|
Key Operating Statistics:
|
|
|
|
|
|
|
|
|
Petroleum Business
|
|
|
|
|
|
|
|
|
Production (barrels per day) (4)
|
|
|
125,614
|
|
|
|
53,689
|
|
Crude oil throughput (barrels per day) (4)
|
|
|
106,530
|
|
|
|
47,267
|
|
Nitrogen Fertilizer Business
|
|
|
|
|
|
|
|
|
Production Volume:
|
|
|
|
|
|
|
|
|
Ammonia (tons in thousands)
|
|
|
83.7
|
|
|
|
86.2
|
|
UAN (tons in thousands)
|
|
|
150.1
|
|
|
|
165.7
|
|
|
|
|
(1)
|
|
Depreciation and amortization is comprised of the following components as excluded from
cost of product sold, direct operating expenses and selling, general administrative
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
|
(in millions)
|
|
Depreciation and amortization included in
cost of product sold
|
|
$
|
0.6
|
|
|
$
|
0.6
|
|
Depreciation and amortization included in
direct operating expenses
|
|
|
18.7
|
|
|
|
13.5
|
|
Depreciation and amortization included in
selling, general and administrative
expenses
|
|
|
0.3
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization
|
|
$
|
19.6
|
|
|
$
|
14.2
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
|
The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income
(loss) and in evaluating our performance due to their unusual or infrequent nature:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Ended March 31,
|
|
|
2008
|
|
2007
|
|
|
(unaudited)
|
|
|
(in millions)
|
Funded letter of credit expense and
interest rate swap not included in
interest expense (a)
|
|
$
|
0.9
|
|
|
$
|
|
|
Major scheduled turnaround expense (b)
|
|
|
|
|
|
|
66.0
|
|
Unrealized loss from Cash Flow Swap
|
|
|
13.9
|
|
|
|
119.7
|
|
|
|
|
|
(a)
|
Consists of fees which are expensed to selling, general and
administrative expenses in connection with the funded letter of credit
facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the
fees are treated as such in the calculation of EBITDA in the Credit Facility.
|
|
|
(b)
|
Represents expenses associated with a major scheduled turnaround at the refinery.
|
|
|
|
|
(3)
|
|
Net income (loss) adjusted for unrealized loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed
in conjunction with the acquisition of Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC on June 24, 2005. On June 16, 2005,
Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of
ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The
derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the
difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil
capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods January 1, 2008 through
June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our Credit Facility and upon meeting specific
requirements related to our leverage ratio and our credit ratings, we may reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of
executed crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010.
|
|
|
|
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result,
our periodic statements of operations reflect in each period material amounts of unrealized gains and losses based on the increases or
decreases in market value of the unsettled position under the swap agreements which are accounted for as a liability on
|
38
|
|
|
|
|
our balance
sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry
to be made to our Statements of Operations. Conversely, as crack spreads decline we are required to record a decrease in the swap
related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the
economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and
losses, and given the significant periodic fluctuations in the
amounts of unrealized gains and losses, management utilizes Net income
(loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business
and assessing its growth and profitability from a strategic and
financial planning perspective, management and our board of directors
considers our U.S. GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We
believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of
operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark
to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment
has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.
|
|
|
|
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be
substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of financial
performance or liquidity in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap
excludes mark to market adjustments, the measure does not reflect the fair market value of our Cash Flow Swap in our net income. As a
result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also,
our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.
|
|
|
|
The following is a reconciliation of Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap to Net income:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
Net income (loss) adjusted for unrealized
loss from Cash Flow Swap
|
|
$
|
30.6
|
|
|
$
|
(82.4
|
)
|
Plus:
|
|
|
|
|
|
|
|
|
Unrealized (loss) from Cash Flow Swap, net
of taxes
|
|
|
(8.4
|
)
|
|
|
(72.0
|
)
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
22.2
|
|
|
$
|
(154.4
|
)
|
|
|
|
(4)
|
|
Barrels per day are calculated by dividing the volume in the period by the number of
calendar days in the period. Barrels per day as shown here is impacted by plant down-time
and other plant disruptions and does not represent the capacity of the facilitys
continuous operations.
|
The following table shows selected information from our petroleum business including refining
margin:
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(unaudited)
|
|
|
|
(in millions, except as otherwise
|
|
|
|
indicated)
|
|
Petroleum Business:
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
1,168.5
|
|
|
$
|
352.5
|
|
Cost of product sold (exclusive of depreciation
and amortization)
|
|
|
1,035.1
|
|
|
|
298.5
|
|
Direct
operating expenses (exclusive of
depreciation and amortization)
|
|
|
40.3
|
|
|
|
96.7
|
|
Net costs associated with flood
|
|
|
5.5
|
|
|
|
|
|
Depreciation and amortization
|
|
|
14.9
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
Gross profit (loss)
|
|
$
|
72.7
|
|
|
$
|
(52.5
|
)
|
Plus direct
operating expenses (exclusive of
depreciation and amortization)
|
|
|
40.3
|
|
|
|
96.7
|
|
Plus net costs associated with flood
|
|
|
5.5
|
|
|
|
|
|
Plus depreciation and amortization
|
|
|
14.9
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
Refining margin (1)
|
|
$
|
133.4
|
|
|
$
|
54.0
|
|
Refining margin per crude oil throughput barrel
|
|
$
|
13.76
|
|
|
$
|
12.69
|
|
Gross profit (loss) per crude oil throughput barrel
|
|
$
|
7.50
|
|
|
$
|
(12.34
|
)
|
Direct
operating expenses (exclusive of
depreciation and amortization) per crude oil throughput barrel
|
|
$
|
4.16
|
|
|
$
|
22.73
|
|
Operating income (loss)
|
|
|
63.6
|
|
|
|
(63.5
|
)
|
39
|
|
|
(1)
|
|
Refining margin is a measurement calculated as the difference between net sales and
cost of product sold (exclusive of depreciation and amortization). Refining margin is a
non-GAAP measure that we believe is important to investors in evaluating our refinerys
performance as a general indication of the amount above our cost of product sold that we
are able to sell refined products. Each of the components used in this calculation (net
sales and cost of product sold exclusive of depreciation and
amortization) is taken
directly from our statement of operations. Our calculation of refining margin may differ
from similar calculations of other companies in our industry, thereby limiting its
usefulness as a comparative measure.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
|
|
(dollars per barrel)
|
Market Indicators
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) crude oil
|
|
$
|
97.82
|
|
|
$
|
58.27
|
|
NYMEX 2-1-1 Crack Spread
|
|
|
11.81
|
|
|
|
12.17
|
|
Crude Oil Differentials:
|
|
|
|
|
|
|
|
|
WTI less WTS (sour)
|
|
|
4.63
|
|
|
|
4.26
|
|
WTI less WCS (heavy sour)
|
|
|
19.84
|
|
|
|
14.80
|
|
WTI less Dated Brent (foreign)
|
|
|
1.10
|
|
|
|
0.51
|
|
PADD II Group 3 versus NYMEX Basis:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
(1.46
|
)
|
|
|
(0.54
|
)
|
Heating Oil
|
|
|
3.65
|
|
|
|
8.77
|
|
PADD II Group 3 versus NYMEX Crack:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
4.95
|
|
|
|
12.43
|
|
Heating Oil
|
|
|
20.77
|
|
|
|
20.57
|
|
|
|
|
|
|
|
|
|
|
Company Operating Statistics
|
|
|
|
|
|
|
|
|
Per barrel profit, margin and expense
of crude oil throughput:
|
|
|
|
|
|
|
|
|
Refining margin
|
|
$
|
13.76
|
|
|
$
|
12.69
|
|
Gross profit (loss)
|
|
|
7.50
|
|
|
|
(12.34
|
)
|
Direct
operating expenses (exclusive of
depreciation and amortization)
|
|
|
4.16
|
|
|
|
22.73
|
|
Per gallon sales price:
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
2.45
|
|
|
|
1.59
|
|
Distillate
|
|
|
2.85
|
|
|
|
1.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
|
|
Barrels
|
|
|
|
|
|
Barrels
|
|
|
|
|
Per Day
|
|
%
|
|
Per Day
|
|
%
|
Selected Company Volumetric Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gasoline
|
|
|
59,662
|
|
|
|
47.5
|
|
|
|
23,499
|
|
|
|
43.8
|
|
Total distillate
|
|
|
48,591
|
|
|
|
38.7
|
|
|
|
21,976
|
|
|
|
40.9
|
|
Total other
|
|
|
17,361
|
|
|
|
13.8
|
|
|
|
8,214
|
|
|
|
15.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total all production
|
|
|
125,614
|
|
|
|
100.0
|
|
|
|
53,689
|
|
|
|
100.0
|
|
Crude oil throughput
|
|
|
106,530
|
|
|
|
89.0
|
|
|
|
47,267
|
|
|
|
92.7
|
|
All other inputs
|
|
|
13,197
|
|
|
|
11.0
|
|
|
|
3,716
|
|
|
|
7.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks
|
|
|
119,727
|
|
|
|
100.0
|
|
|
|
50,983
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
|
Barrels
|
|
%
|
|
Barrels
|
|
%
|
Crude oil throughput by crude type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet
|
|
|
6,573,627
|
|
|
|
67.8
|
|
|
|
2,782,136
|
|
|
|
65.4
|
|
Light/medium sour
|
|
|
1,785,669
|
|
|
|
18.4
|
|
|
|
1,454,878
|
|
|
|
34.2
|
|
Heavy sour
|
|
|
1,334,889
|
|
|
|
13.8
|
|
|
|
17,016
|
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil throughput
|
|
|
9,694,185
|
|
|
|
100.0
|
|
|
|
4,254,030
|
|
|
|
100.0
|
|
40
The tables below provide an overview of the nitrogen fertilizer business results of operations, relevant market
indicators and its key operating statistics:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
|
|
(unaudited)
|
|
|
(in millions, except as otherwise indicated)
|
Nitrogen Fertilizer Business:
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
62.6
|
|
|
$
|
38.6
|
|
Cost of product sold (exclusive of
depreciation and amortization)
|
|
|
8.9
|
|
|
|
6.1
|
|
Direct
operating expenses
(exclusive of depreciation and
amortization)
|
|
|
20.3
|
|
|
|
16.7
|
|
Depreciation and amortization
|
|
|
4.5
|
|
|
|
4.4
|
|
Operating income
|
|
|
26.0
|
|
|
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
Market Indicators
|
|
|
|
|
|
|
|
|
Natural gas
(dollars per MMBtu)
|
|
$
|
8.74
|
|
|
$
|
7.17
|
|
Ammonia Southern Plains (dollars per ton)
|
|
|
590
|
|
|
|
389
|
|
UAN Corn Belt (dollars per ton)
|
|
|
371
|
|
|
|
239
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
Company Operating Statistics
|
|
|
|
|
|
|
|
|
Production (thousand tons):
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
83.7
|
|
|
|
86.2
|
|
UAN
|
|
|
150.1
|
|
|
|
165.7
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
233.8
|
|
|
|
251.9
|
|
|
|
|
|
|
|
|
|
|
Sales (thousand tons) (1):
|
|
|
|
|
|
|
|
|
Ammonia
|
|
|
24.1
|
|
|
|
20.7
|
|
UAN
|
|
|
158.0
|
|
|
|
166.8
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
182.1
|
|
|
|
187.5
|
|
|
|
|
|
|
|
|
|
|
Product pricing (plant gate) (dollars per ton) (1):
|
|
|
|
|
|
|
|
|
Ammonia
|
|
$
|
494
|
|
|
$
|
347
|
|
UAN
|
|
|
262
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
On-stream factor (2):
|
|
|
|
|
|
|
|
|
Gasification
|
|
|
91.8
|
%
|
|
|
91.8
|
%
|
Ammonia
|
|
|
90.7
|
%
|
|
|
86.3
|
%
|
UAN
|
|
|
85.9
|
%
|
|
|
89.4
|
%
|
|
|
|
|
|
|
|
|
|
Reconciliation to net sales (dollars in thousands):
|
|
|
|
|
|
|
|
|
Freight in revenue
|
|
$
|
4,022
|
|
|
$
|
3,139
|
|
Hydrogen revenue
|
|
|
5,291
|
|
|
|
|
|
Sales net plant gate
|
|
|
53,287
|
|
|
|
35,436
|
|
|
|
|
|
|
|
|
|
|
Total net sales
|
|
|
62,600
|
|
|
|
38,575
|
|
|
|
|
(1)
|
|
Plant gate sales per ton represents net sales less freight
and hydrogen revenue divided by product
sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order
to provide a pricing measure that is comparable across the fertilizer industry.
|
|
(2)
|
|
On-stream factor is the total number of hours operated divided by the total number of
hours in the reporting period.
|
41
Three
Months Ended March 31, 2008 Compared to the Three Months Ended March
31, 2007
Consolidated
Results of Operations
Net
Sales.
Consolidated net sales were $1,223.0 million for the three months ended March 31,
2008 compared to $390.5 million for the three months ended
March 31, 2007. The increase of $832.5
million for the three months ended March 31, 2008 as compared to the three months ended March 31,
2007 was primarily due to an increase in petroleum net sales of $816.0 million that resulted from
higher sales volumes ($592.1 million) primarily resulting from the refinery turnaround which began
in February 2007 and was completed in April 2007 and higher product prices ($223.9 million).
Nitrogen fertilizer net sales increased $24.0 million for the three months ended March 31, 2008 as
compared to the three months ended March 31, 2007 primarily due
to higher plant gate prices, partially offset by reductions in overall
sales volume.
Cost of Product Sold Exclusive of Depreciation and Amortization.
Consolidated cost of product
sold exclusive of depreciation and amortization was $1,036.2 million for the three months ended
March 31, 2008 as compared to $303.7 million for the three months ended March 31, 2007. The
increase of $732.5 million for the three months ended March 31, 2008 as compared to the three
months ended March 31, 2007 primarily resulted from a significant increase in refined fuel
production volumes over the comparable period due to the refinery turnaround which began in
February 2007 and was completed in April 2007.
Direct Operating Expenses Exclusive of Depreciation and Amortization.
Consolidated direct
operating expenses exclusive of depreciation and amortization were $60.6 million for the three
months ended March 31, 2008 as compared to $113.4 million for the three months ended March 31,
2007. This decrease of $52.8 million for the three months ended March 31, 2008 as compared to the
three months ended March 31, 2007 was due to a decrease in petroleum direct operating expenses of
$56.4 million, primarily related to decreases in expenses associated with the refinery turnaround
and labor, partially offset by increases in expenses associated with utilities and energy, repairs
and maintenance, production chemicals, taxes and environmental. Nitrogen fertilizer direct
operating expenses increased during the comparable period by $3.6 million, primarily due to
increases in expenses associated with taxes, repairs and maintenance, labor, catalysts and outsides
services, partially offset by decreases in expenses associated with utilities, royalties and other
and equipment rental. The nitrogen fertilizer facility was subject to a property tax abatement
which expired beginning in 2008. We have estimated our accrued property tax liability based upon
the assessment value received by the county.
Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization.
Consolidated selling, general and administrative expenses were $13.4 million for the three months
ended March 31, 2008 as compared to $13.2 million for the three months ended March 31, 2007. This
variance was primarily the result of decreases in administrative labor ($3.0 million) primarily
related to deferred compensation which was more than offset by increases in expenses related to
outside services ($2.2 million), bad debt ($0.4 million), insurance ($0.3 million), bank charges
($0.2 million), public relations ($0.1 million) and other selling, general and administrative costs
($0.1 million).
Net Costs Associated with Flood.
Consolidated net costs associated with flood for the three
months ended March 31, 2008 approximated $5.8 million as compared to none for the three months
ended March 31, 2007. As the flood occurred in the second and third quarter of 2007 there was no
financial statement impact in the first quarter of 2007. Total gross costs recorded for the three
months ended March 31, 2008 were approximately $7.6 million. Of these gross costs, approximately
$3.8 million were associated with repair and other matters as a result of the damage to the
Companys facilities. Included in this cost was $0.3 million of professional fees and $3.5 million
for other repair and related costs. There were also approximately $3.8 million of costs recorded with
respect to environmental remediation and property damage. Total accounts receivable from
insurers approximated $85.7 million at March 31, 2008, for which we believe collection is probable.
Depreciation and Amortization.
Consolidated depreciation and amortization was $19.6 million
for the three months ended March 31, 2008 as compared to $14.2 million for the three months ended
March 31, 2007. The increase in depreciation and amortization
for the three months ended March 31, 2008 as compared to the
three months ended March 31, 2007 was primarily the
result of the completion of several large capital projects.
Operating Income.
Consolidated operating income was $87.4 million for the three months ended
March 31, 2008 as compared to an operating loss of $54.0 million for the three months ended March
31, 2007. For the three
42
months ended March 31, 2008 as compared to the three months ended March 31, 2007, petroleum
operating income increased $127.1 million and nitrogen fertilizer operating income increased by
$16.7 million.
Interest Expense.
Consolidated interest expense for the three months ended March 31, 2008 was
$11.3 million as compared to interest expense of $11.9 million for the three months ended March 31,
2007. This 5% decrease for the three months ended March 31, 2008 as compared to the three months
ended March 31, 2007 primarily resulted from an overall decrease in the index rates (primarily
LIBOR) and a decrease in average borrowings outstanding during the comparable periods.
Interest Income.
Interest income was $0.7 million for the three months ended March 31, 2008 as
compared to $0.5 million for the three months ended March 31, 2007.
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,
2008, we incurred $47.9 million in losses on derivatives. This compares to a $137.0 million loss on
derivatives for the three months ended March 31, 2007. This significant decrease in loss on
derivatives, net for the three months ended March 31, 2008 as compared to the three months ended March
31, 2007 was primarily attributable to the realized and unrealized losses on our Cash Flow Swap.
Realized losses on the Cash Flow Swap for the three months ended March 31, 2008 and the three
months ended March 31, 2007 were $21.5 million and $8.5 million, respectively. The increase in
realized losses over the comparable periods was primarily the result of higher average crack
spreads for the three months ended March 31, 2008 as compared to the three months ended March 31,
2007. Unrealized losses represent the change in the mark-to-market value on the unrealized portion
of the Cash Flow Swap based on changes in the NYMEX crack spread that is the basis for the Cash
Flow Swap. Unrealized losses on our Cash Flow Swap for the three months ended March 31, 2008 and
the three months ended March 31, 2007 were $13.9 million and $119.7 million, respectively. This
change in the unrealized loss of the Cash Flow Swap over the comparable periods reflect decreases
in the crack spread values on the unrealized positions comprising the Cash Flow Swap. In addition
to the change in the NYMEX crack spread, the outstanding term of the Cash Flow Swap at the end of
each period also affects the impact that the changes of the underlying crack spread may have on the
unrealized gain or loss. As of March 31, 2008, the Cash Flow Swap had a remaining term of
approximately two years and three months whereas as of March 31, 2007 the remaining term on the
Cash Flow Swap was approximately three years and three months. As a
result of the shorter remaining
term as of March 31, 2008, a similar change in crack spread will
have a smaller impact on the
unrealized gains or losses.
Provision for Income Taxes.
Income tax expense for the three months ended March 31, 2008 was
$6.9 million, or 23.6% of income before income taxes, as compared to income tax benefit of $(47.3)
million, or 23.4% of earnings before income taxes, for the three months ended March 31, 2007.
Minority Interest in (income) loss of Subsidiaries.
Minority interest in loss of subsidiaries
for the three months ended March 31, 2007 was $0.7 million compared to none during the three months
ended March 31, 2008. Minority interest for 2007 related to common stock in two of our subsidiaries
owned by our chief executive officer. In October 2007, in connection with our initial public
offering, our chief executive officer exchanged his common stock in our subsidiaries for common
stock of CVR.
Net Income.
For the three months ended March 31, 2008, net income increased to $22.2 million
as compared to net loss of $(154.4) million for the three months ended March 31, 2007. Net income
increased $176.6 million compared to the first quarter of 2007 primarily due to the planned turnaround that commenced in February 2007.
For the three months ended March 31, 2007 the Company incurred costs of $66.0 million associated with
the refinery turnaround. In addition the Companys net income was impacted by a significant change in the
fair value of the Cash Flow Swap over the comparable periods.
Petroleum
Results of Operations
Net Sales.
Petroleum net sales were $1,168.5 million for the three months ended March 31, 2008
compared to $352.5 million for the three months ended March 31, 2007. The increase of $816.0
million during the three months ended March 31, 2008 as compared to the three months ended March
31, 2007 was primarily the result of significantly higher sales volumes ($592.1 million) and higher
product prices ($223.9 million). Overall sales volumes of refined fuels for the three months ended
March 31, 2008 increased 110% as compared to the three months ended March 31, 2007. The increased
sales volume primarily resulted from a significant increase in refined fuel
43
production volumes over the comparable periods due to the refinery turnaround which began
in February 2007 and was completed in April 2007. Our average sales price per gallon for the three
months ended March 31, 2008 for gasoline of $2.45 and distillate of $2.85 increased by 54% and 60%,
respectively, as compared to the three months ended March 31, 2007.
Cost of Product Sold Exclusive of Depreciation and Amortization.
Cost of product sold includes
cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation
and distribution costs. Petroleum cost of product sold exclusive of depreciation and amortization
was $1,035.1 million for the three months ended March 31, 2008 compared to $298.5 million for the
three months ended March 31, 2007. The increase of $736.6 million during the three months ended
March 31, 2008 as compared to the three months ended March 31, 2007 was primarily the result of a
significant increase in crude throughput due to refinery downtime from the refinery turnaround
which began in February 2007 and was completed in April 2007. In addition to the refinery
turnaround, higher crude oil prices, increased sales volumes and the impact of FIFO accounting also
impacted cost of product sold during the comparable periods. Our average cost per barrel of crude
oil consumed for the three months ended March 31, 2008 was $92.35 compared to $51.98 for the
comparable period of 2007, an increase of 78%. Sales volume of refined fuels increased 110% for the
three months ended March 31, 2008 as compared to the three months ended March 31, 2007. In
addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in
the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in
FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices
decrease. For the three months ended March 31, 2008, we had FIFO inventory gains of $20.0 million
compared to FIFO inventory gains of $5.2 million for the comparable period of 2007. In 2007, as a result of the flood, our refinery exceeded the required
average annual gasoline sulfur standard as mandated by our approved hardship waiver with the Environmental Protection Agency
(EPA). In anticipation of a settlement with the EPA to resolve the non-compliance, we accrued a liability of
approximately $3.5 million in the fourth quarter of 2007. During 2008, the matter was resolved with the EPA and accordingly,
the liability was reversed resulting in a reduction to cost of product sold (exclusive of depreciation and
amortization) of approximately $3.5 million in the first quarter of 2008.
Refining margin per barrel of crude throughput increased from $12.69 for the three months
ended March 31, 2007 to $13.76 for the three months ended
March 31, 2008. Gross profit per barrel increased to $7.50 in
the first quarter of 2008, up from a loss of $(12.34) in the
equivalent period in 2007. The primary contributors
to the positive variance in refining margin per barrel of crude throughput were an increase in FIFO
inventory gains and increases in crude oil differentials over the comparable periods. Increased
discounts for sour crude oils evidenced by the $0.37 per barrel, or 9%, increase in the spread
between the WTI price, which is a market indicator for the price of light sweet crude, and the WTS
price, which is an indicator for the price of sour crude, positively impacted refining margin for
the three months ended March 31, 2008 as compared to the three months ended March 31, 2007.
Partially offsetting the positive effects of FIFO inventory gains and crude oil differentials was
the 3% decrease ($0.36 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable
periods and negative regional differences between gasoline prices in our primary marketing region
(the Coffeyville supply area) and those of the NYMEX. The average gasoline basis for the three
months ended March 31, 2008 decreased by $0.92 per barrel to ($1.46) per barrel compared to ($0.54)
per barrel in the comparable period of 2007. The average distillate basis decreased by $5.12 per
barrel to $3.65 per barrel compared to $8.77 per barrel in the comparable period of 2007.
Direct Operating Expenses Exclusive of Depreciation and Amortization.
Direct operating
expenses for our petroleum operations include costs associated with the actual operations of our
refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance
(turnaround), labor and environmental compliance costs. Petroleum direct operating expenses
exclusive of depreciation and amortization were $40.3 million for the three months ended March 31,
2008 compared to direct operating expenses of $96.7 million for the three months ended March 31,
2007. The decrease of $56.4 million for the three months ended March 31, 2008 compared to the three
months ended March 31, 2007 was the result of decreases in expenses associated with refinery
turnaround ($66.0 million) and direct labor ($1.7 million). These decreases in direct operating
expenses were partially offset by increases in expenses associated with utilities and energy ($4.3
million), repairs and maintenance ($3.0 million), production chemicals ($2.1 million), property
taxes ($0.8 million) and environmental ($0.5 million). On a per barrel of crude throughput basis,
direct operating expenses per barrel of crude oil throughput for the three months ended March 31,
2008 decreased to $4.16 per barrel as compared to $22.73 per barrel for the three months ended
March 31, 2007 principally due to the 2007 downtime at the refinery for planned major maintenance
and the corresponding impact on overall crude oil throughput and production volume.
Net Costs Associated with Flood.
Petroleum net costs associated with flood for the three
months ended March 31, 2008 approximated $5.5 million. As the flood occurred in the second and
third quarter of 2007, there were no flood related costs incurred in the first quarter of 2007.
Total gross costs recorded for the three months ended March 31, 2008 were approximately $6.8
million. Of these gross costs approximately $3.0 million were associated with repair and other
matters as a result of the physical damage to the refinery and approximately $3.8
44
million were associated with the environmental remediation and property damage. Total
accounts receivable from insurers approximated $81.2 million at March 31, 2008, for which we
believe collection is probable.
Depreciation and Amortization.
Petroleum depreciation and amortization was $14.9 million for
the three months ended March 31, 2008 as compared to $9.8 million for the three months ended March 31,
2007. This increase in petroleum depreciation and amortization for the three months ended March 31,
2008 as compared to the three months ended March 31, 2007 was primarily the result of the
completion of several large capital projects.
Operating Income.
Petroleum operating income was $63.6 million for the three months ended
March 31, 2008 as compared to an operating loss of $63.5 million for the three months ended March
31, 2007. This increase of $127.1 million from the three months ended March 31, 2008 as compared to
the three months ended March 31, 2007 was primarily the result of the refinery turnaround which
began in February 2007 and was completed in April 2007 and decreases in expenses associated with
refinery turnaround ($66.0 million) and direct labor ($1.7 million). These decreases in direct
operating expenses were partially offset by increases in expenses associated with utilities and
energy ($4.3 million), repairs and maintenance ($3.0 million), production chemicals ($2.1 million),
taxes ($0.8 million) and environmental ($0.5 million).
Fertilizer
Results of Operations
Net Sales.
Nitrogen fertilizer net sales were $62.6 million for the three months ended March
31, 2008 compared to $38.6 million for the three months ended March 31, 2007. The increase of $24.0
million for the three months ended March 31, 2008 as compared to the three months ended March 31,
2007 was the result of higher plant gate prices, together with a
change in intercompany accounting for hydrogen
from cost of product sold (exclusive of depreciation and amortization) to net sales over the
comparable periods, which eliminates in consolidation, partially offset by reductions in overall sales volume.
In regard to product sales volumes for the three months ended March 31, 2008, our nitrogen
fertilizer operations experienced an increase of 17% in ammonia sales unit volumes and a decrease
of 5% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total
hours in the reporting period) for the gasification unit were unchanged over the comparable
periods. On-stream factors for the ammonia unit were greater than the three months ended March 31,
2007. On-stream factors for the UAN plant were lower than the three month period ended March 31,
2007. During the three months ended March 31, 2008, all three primary nitrogen fertilizer units
experienced approximately five days of downtime associated with repairs to the air separation unit.
It is typical to experience brief outages in complex manufacturing operations such as our nitrogen
fertilizer plant which result in less than one hundred percent on-stream availability for one or
more specific units.
Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver
the product. We believe plant gate price is meaningful because we sell products both FOB our plant
gate (sold plant) and FOB the customers designated delivery site (sold delivered) and the
percentage of sold plant versus sold delivered can change month to month or three months to three
months. The plant gate price provides a measure that is consistently comparable period to period.
Plant gate prices for the three months ended March 31, 2008 for ammonia and UAN were greater than
plant gate prices for the comparable period of 2007 by 43% and 55%, respectively. This dramatic
increase in nitrogen fertilizer prices was not the direct result of an increase in natural gas
prices, but rather the result of increased demand for nitrogen-based fertilizers due to the
increased use of corn for the production of ethanol and an overall increase in prices for corn,
wheat and soybeans, the primary row crops in our region. This increase in demand for nitrogen-based
fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from
their traditional correlation to natural gas prices.
The demand for fertilizer is affected by the aggregate crop planting decisions and fertilizer
application rate decisions of individual farmers. Individual farmers make planting decisions based
largely on the prospective profitability of a harvest, while the specific varieties and amounts of
fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions,
weather patterns and the types of crops planted.
Cost of Product Sold Exclusive of Depreciation and Amortization.
Cost of product sold
exclusive of depreciation and amortization is primarily comprised of pet coke expense and freight
and distribution expenses. Cost of product sold (excluding depreciation and amortization) for the
three months ended March 31, 2008 was $8.9 million compared to $6.1 million for the three months
ended March 31, 2007. The increase of $2.8 million for the three months ended March 31, 2008 as
compared to the three months ended March 31, 2007 was primarily the result
45
of a change in accounting for hydrogen reimbursement. For the three months ended March 31,
2007, hydrogen reimbursement was included in cost of product sold (exclusive of depreciation and
amortization). For the three months ended March 31, 2008, hydrogen has been included in net sales.
These amounts eliminate in consolidation. Hydrogen is transferred from our nitrogen fertilizer operations to our petroleum operations to
facilitate sulfur recovery in the ultra low sulfur diesel production unit.
Direct Operating Expenses Exclusive of Depreciation and Amortization.
Direct operating
expenses for our nitrogen fertilizer operations include costs associated with the actual operations
of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and
chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct
operating expenses exclusive of depreciation and amortization for the three months ended March 31,
2008 were $20.3 million as compared to $16.7 million for the three months ended March 31, 2007. The
increase of $3.6 million for the three months ended March 31, 2008 as compared to the three months
ended March 31, 2007 was primarily the result of increases in expenses associated with property
taxes ($2.5 million), repairs and maintenance ($1.7 million), labor ($0.3 million), catalysts ($0.3
million) and outside services ($0.2 million). These increases in direct operating expenses were
partially offset by decreases in expenses associated with utilities ($0.6 million), royalties and
other ($0.4 million) and equipment rental ($0.3 million).
Depreciation and Amortization.
Nitrogen fertilizer depreciation and amortization increased to
$4.5 million for the three months ended March 31, 2008 as compared to $4.4 million for the three
months ended March 31, 2007. Nitrogen fertilizer depreciation and amortization increased by
approximately $0.1 million for the three months ended March 31, 2008 compared to the three months
ended March 31, 2007.
Operating Income.
Nitrogen fertilizer operating income was $26.0 million for the three months
ended March 31, 2008 as compared to operating income of $9.3 million for the three months ended
March 31, 2007. This increase of $16.7 million for the three months ended March 31, 2008 as
compared to the three months ended March 31, 2007 was primarily the result of increased fertilizer
prices over the comparable periods. Additionally, decreased direct operating expenses associated
with utilities ($0.6 million), royalties and other ($0.4 million) and equipment rental ($0.3
million) also contributed to the positive operating income comparison over the comparable periods.
These decreases in expenses were partially offset by reduced sales volumes and increased direct
operating expenses primarily the result of increases in taxes ($2.5 million), repairs and
maintenance ($1.7 million), labor ($0.3 million), catalysts ($0.3 million) and outside services
($0.2 million).
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from our operating activities, existing
cash balances and our existing revolving credit facility. Additionally, we have borrowings from
related parties. Our ability to generate sufficient cash flows from our operating activities will
continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities
of refined products at margins sufficient to cover fixed and variable expenses.
Our liquidity was enhanced during the fourth quarter of 2007 by the receipt of $408.5 million
of net proceeds from our initial public offering after the payment of underwriting discounts and
commissions, but before the deduction of offering expenses. We believe that our cash flows from
operations, borrowings under our revolving credit facility,
third party guarantees and other capital resources will be sufficient to satisfy the anticipated cash
requirements associated with our existing operations for at least the next 12 months. However, our
future capital expenditures and other cash requirements could be higher than we currently expect as
a result of various factors. Additionally, our ability to generate sufficient cash from our
operating activities depends on our future performance, which is subject to general economic,
political, financial, competitive, and other factors beyond our control.
46
Debt
Credit Facility
On December 28, 2006, our subsidiary Coffeyville Resources, LLC entered into a Credit Facility
which provided financing of up to $1.075 billion. The Credit Facility consisted of $775.0 million
of tranche D term loans, a $150.0 million revolving credit facility, and a funded letter of credit
facility of $150.0 million issued in support of the Cash Flow Swap. On October 26, 2007, we repaid
$280.0 million of the tranche D term loans with proceeds from our initial public offering. The
Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of
their assets including the equity of our subsidiaries on a first lien priority basis.
The tranche D term loans outstanding are subject to quarterly principal amortization payments
of 0.25% of the outstanding balance commencing on April 1, 2007 and increasing to 23.5% of the
outstanding principal balance on April 1, 2013 and the next two quarters, with a final payment of
the aggregate outstanding balance on December 28, 2013.
The revolving loan facility of $150.0 million provides for direct cash borrowings for general
corporate purposes and on a short-term basis. Letters of credit issued under the revolving loan
facility are subject to a $75.0 million sub-limit. The revolving loan commitment expires on
December 28, 2012. The borrower has an option to extend this maturity upon written notice to the
lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the
term loans, which is December 28, 2013. As of March 31, 2008, we had available $112.6 million under
the revolving credit facility.
The $150.0 million funded letter of credit facility provides credit support for our
obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash
collateralized by the funding by the lenders of cash into a credit linked deposit account. This
account is held by the funded letter of credit issuing bank. Contingent upon the requirements of
the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time
upon written notice to the lenders. The funded letter of credit facility expires on December 28,
2010.
The Credit Facility incorporates the following pricing by facility type:
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Tranche D term loans bear interest at either (a) the greater of the prime rate
and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the
borrowers option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal
funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon
achievement of certain rating conditions).
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Revolving loan borrowings bear interest at either (a) the greater of the prime
rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at
the borrowers option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal
funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon
achievement of certain rating conditions).
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Letters of credit issued under the $75.0 million sub-limit available under the
revolving loan facility are subject to a fee equal to the applicable margin on
revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per
annum owing to the issuing lender.
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Funded letters of credit are subject to a fee equal to the applicable margin on
term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of
0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a
fee of 0.10% to the administrative agent on a quarterly basis based on the average
balance of funded letters of credit outstanding during the calculation period, for the
maintenance of a credit-linked deposit account backstopping funded letters of credit.
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In addition to the fees stated above, the Credit Facility requires the borrower to pay 0.50%
per annum in commitment fees on the unused portion of the revolving loan facility.
The Credit Facility requires the borrower to prepay outstanding loans, subject to certain
exceptions, with:
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100% of the net asset sale proceeds received from specified asset sales and net
insurance/ condemnation proceeds, if the borrower does not reinvest those proceeds in
assets to be used in its
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47
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business or make other permitted investments within 12 months or if, within 12 months of
receipt, the borrower does not contract to reinvest those proceeds in assets to be used
in its business or make other permitted investments within 18 months of receipt, each
subject to certain limitations;
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100% of the cash proceeds from the incurrence of specified debt obligations;
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75% of consolidated excess cash flow less 100% of voluntary prepayments made
during the fiscal year; provided that with respect to any fiscal year commencing with
fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the
end of such fiscal year is less than 1.50:1.00 or 25% if the total leverage ratio as of
the end of such fiscal year is less than 1.00:1.00
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Mandatory prepayments will be applied first to the term loan, second to the swing line loans,
third to the revolving loans, fourth to outstanding reimbursement obligations with respect to
revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving
letters of credit and funded letters of credit. Voluntary prepayments of loans under the Credit
Facility are permitted, in whole or in part, at the borrowers option, without premium or penalty.
The Credit Facility contains customary covenants. These agreements, among other things,
restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its
subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior
payments, enter into agreements that restrict subsidiary distributions, make investments, loans or
advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests,
enter into sale and leaseback transactions, engage in certain transactions with affiliates and
stockholders, change the business conducted by the credit parties, and enter into hedging
agreements. The Credit Facility provides that Coffeyville Resources, LLC may not enter into
commodity agreements if, after giving effect thereto, the exposure under all such commodity
agreements exceeds 75% of Actual Production (the borrowers estimated future production of refined
products based on the actual production for the three prior months) or for a term of longer than
six years from December 28, 2006. In addition, the borrower may not enter into material amendments
related to any material rights under the Cash Flow Swap or the Partnerships partnership agreement
without the prior written approval of the lenders. These limitations are subject to critical
exceptions and exclusions and are not designed to protect investors in our common stock.
The Credit Facility also requires the borrower to maintain certain financial ratios as
follows:
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Minimum
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interest
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Maximum
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coverage
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leverage
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Fiscal quarter ending
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ratio
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ratio
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March 31, 2008
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3.25:1.00
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3.25:1.00
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June 30, 2008
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3.25:1.00
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3.00:1.00
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September 30, 2008
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3.25:1.00
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2.75:1.00
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December 31, 2008
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3.25:1.00
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2.50:1.00
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March 31, 2009 and thereafter
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3.75:1.00
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2.25:1.00
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to December 31, 2009,
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2.00:1.00 thereafter
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The computation of these ratios is governed by the specific terms of the Credit Facility and
may not be comparable to other similarly titled measures computed for other purposes or by other
companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to
consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the
ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The
computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general,
under the terms of our Credit Facility, consolidated adjusted EBITDA is calculated by adding
consolidated net income, consolidated interest expense, income taxes, depreciation and
amortization, other non- cash expenses, any fees and expenses related to permitted acquisitions,
any non-recurring expenses incurred in connection with the issuance
of debt or equity, management
fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net
after-tax loss from disposed or discontinued operations, any incremental property taxes related to
abatement non-renewal, any losses attributable to minority equity interests and major scheduled
turnaround expenses. As of March 31, 2008, we were in compliance with our covenants under the
Credit Facility.
48
We present consolidated adjusted EBITDA because it is a material component of material
covenants within our current Credit Facility and significantly impacts our liquidity and ability to
borrow under our revolving line of credit. However, consolidated adjusted EBITDA is not a defined
term under GAAP and should not be considered as an alternative to operating income or net income as
a measure of operating results or as an alternative to cash flows as a measure of liquidity.
Consolidated adjusted EBITDA is calculated under the Credit Facility as follows:
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Three Months Ended
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March 31,
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2008
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2007
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(unaudited in millions)
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Consolidated Financial Results
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Net income (loss)
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$
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22.2
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$
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(154.4
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)
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Plus:
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Depreciation and amortization
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19.6
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14.2
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Interest
expense and other financing costs
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11.3
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11.9
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Income tax expense (benefit)
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6.9
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(47.3
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)
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Funded letters of credit expense and interest
rate swap not included in interest expense
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0.9
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Major scheduled turnaround expense
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66.0
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Unrealized (gain) or loss on derivatives
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18.9
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126.9
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Non-cash compensation expense for equity awards
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(0.4
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3.7
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Minority interest
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(0.7
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Management fees
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0.5
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Adjusted EBITDA
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$
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79.4
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$
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20.8
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In addition to the financial covenants summarized in the table above, the Credit Facility
restricts the capital expenditures of Coffeyville Resources, LLC to $125 million in 2008,
$125 million in 2009, $80 million in 2010, and $50 million in 2011 and thereafter. The capital
expenditures covenant includes a mechanism for carrying over the excess of any previous years
capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year
commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to
1.25:1.00 for any quarter commencing with the quarter ended December 31, 2008. We believe the
limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our
current capital expenditure needs. However, if future events require us or make it beneficial for
us to make capital expenditures beyond those currently planned, we would need to obtain consent
from the lenders under our Credit Facility.
The Credit Facility also contains customary events of default. The events of default include
the failure to pay interest and principal when due, including fees and any other amounts owed under
the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any
representation or warranty contained in the Credit Facility, any default under any of the documents
entered into in connection with the Credit Facility, the failure to pay principal or interest or
any other amount payable under other debt arrangements in an aggregate amount of at least
$20 million, a breach or default with respect to material terms under other debt arrangements in an
aggregate amount of at least $20 million which results in the debt becoming payable or declared due
and payable before its stated maturity, a breach or default under the Cash Flow Swap that would
permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and
attachments exceeding $20 million, events relating to employee benefit plans resulting in liability
in excess of $20 million, a change in control, the guarantees, collateral documents or the Credit
Facility failing to be in full force and effect or being declared null and void, any guarantor
repudiating its obligations, the failure of the collateral agent under the Credit Facility to have
a lien on any material portion of the collateral, and any party under the Credit Facility (other
than the agent or lenders under the Credit Facility) contesting the validity or enforceability of
the Credit Facility.
Under the terms of our Credit Facility, our initial public offering was deemed a Qualified
IPO because the offering generated at least $250 million of gross proceeds and we used the
proceeds of the offering to repay at least $275 million of term loans under the Credit Facility. As
a result of our Qualified IPO, the interest margin on LIBOR loans may in the future decrease from
3.25% to 2.75% (if we have credit ratings of B2/B) or 2.50% (if we have credit ratings of B1/B+).
Interest on base rate loans will similarly be adjusted. In addition, as a result of our Qualified
IPO, (1) we will be allowed to borrow an additional $225 million under the Credit Facility after
June 30, 2008 to finance capital enhancement projects if we are in pro forma compliance with the
financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we will
be allowed to pay an additional $35 million of dividends each year, if our corporate family ratings
are at least B2 from Moodys and B from S&P, (3) we will
49
not be subject to any capital expenditures limitations commencing with fiscal 2009 if our
total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter
ended December 31, 2008, and (4) at any time after March 31, 2008 we will be allowed to reduce the
Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow
Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or
equal to 1.25:1 and we have a corporate family rating of at least B2 from Moodys and B from S&P.
The Credit Facility is subject to an intercreditor agreement among the lenders and the Cash
Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds
of sale of collateral.
At March 31, 2008 and December 31, 2007, funded long-term debt, including current maturities,
totaled $488.0 million and $489.2 million, respectively, of tranche D term loans. Other commitments
at March 31, 2008 and December 31, 2007 included a $ 150.0 million funded letter of credit facility
and a $150.0 million revolving credit facility. As of March 31, 2008, the commitment outstanding on
the revolving credit facility was $37.4 million, including $5.8 million in letters of credit in support of
certain environmental obligations and $ 31.6 million in letters of credit to secure transportation
services for crude oil. As of December 31, 2007, the commitment outstanding on the revolving credit
facility was $39.4 million, including $5.8 million in letters of credit in support of certain environmental
obligations, $3.0 million in support of surety bonds in place to support state and federal excise
tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for
crude oil.
Payment Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our operations on June 30, 2007,
Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to
the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 the payment of
approximately $123.7 million (plus accrued interest) which we owed to J. Aron. J. Aron has agreed
to further defer these payments to August 31, 2008 but we will be required to use 37.5% of our
consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred
amounts. As of March 31, 2008 we were not required to repay any portion of the deferred
amount.
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On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into
a letter agreement in which J. Aron deferred to August 7, 2007 a $45 million payment
which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007.
We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%.
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On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter
agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment
which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007.
J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS
Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to
guarantee one half of the payment and (b) interest accrued on the $43.7 million from
July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.
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On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter
agreement in which J. Aron deferred to September 7, 2007 both the $45 million payment
due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25,
2007 (and accrued interest). J. Aron deferred these payments on the conditions that
(a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P.
agreed to guarantee one half of the payments and (b) interest accrued on the amounts
from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.
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On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a
letter agreement in which J. Aron deferred to January 31, 2008 the $45 million payment
due September 7, 2007 (and accrued interest), the $43.7 million payment due
September 7, 2007 (and accrued interest) and the $35 million payment which we owed to
J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J.
Aron deferred these payments (totaling $123.7 million plus accrued interest) on the
conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment
Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest
accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%.
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50
Nitrogen Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time to time, seek to raise capital
through a public or private offering of limited partner interests in the Partnership. Any decision
to pursue such a transaction would be made in the discretion of the managing general partner, not
us, and any proceeds raised in a primary offering would be for the benefit of the Partnership, not
us (although in some cases, depending on the structure of the transaction, the Partnership might
remit proceeds to us). As discussed elsewhere, the Partnership has
filed a registration statement with the SEC regarding a potential
initial public offering of limited partner interests, although there
is no assurance that the Partnership will consummate any such offering
on the terms described in the registration statement, or at all. If the managing general partner elects to pursue a public or private
offering of limited partner interests in the Partnership, we expect that any such transaction would
require amendments to our Credit Facility, as well as the Cash Flow Swap, in order to remove the
Partnership and its subsidiaries as obligors under such instruments. Any such amendments could
result in significant changes to our Credit Facilitys pricing, mandatory repayment provisions,
covenants and other terms and could result in increased interest costs and require payment by us of
additional fees. We have agreed to use our commercially reasonable efforts to obtain such
amendments if the managing general partner elects to cause the Partnership to pursue a public or
private offering and gives us at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any such amendment on terms
acceptable to us or at all. If we are not able to amend our Credit Facility on terms satisfactory
to us, we may need to refinance them with other facilities. We will not be considered to have used
our commercially reasonable efforts to obtain such amendments if we do not effect the requested
modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of
this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the
terms required by the lenders including covenants, events of default and repayment and prepayment
provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a
material adverse effect on us. In order to effect the requested amendments, we may require that
(1) the Partnerships initial public or private offering generate at least $140 million in net
proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or
incurrence of indebtedness) equal to $75 million minus the amount of capital expenditures it will
reimburse us for from the proceeds of its initial public or private offering and to distribute that
cash to us prior to, or concurrently with, the closing of its initial public or private offering.
If the managing general partner sells interests to third party investors, we expect that the
Partnership may at such time seek to enter into its own credit facility.
In addition, we may elect to sell our interests in the Partnership in a secondary public
offering (either in connection with a public offering by the Partnership, but subject to priority
rights in favor of the Partnership, or following completion of the Partnerships initial public
offering, if any) or in a private placement. Neither the consent of the managing general partner
nor the consent of the Partnership is required for any sale of our interests in the Partnership,
other than customary blackout periods relating to offerings by the Partnership. Any proceeds raised
would be for our benefit. The Partnership has granted us registration rights which will require the
Partnership to register our interests with the SEC at our request from time to time (following any
public offering by the Partnership), subject to various limitations and requirements.
Capital
Spending
In
2007, as a result of the flood, our refinery exceeded the required
average annual gasoline sulfur standard as mandated by our approved
hardship waiver with the EPA. In anticipation of a settlement with
the EPA to resolve the non-compliance, the Company planned to spend
$28.0 million in capital required for interim compliance with the ultra
low sulfur gasoline standards in 2008, ahead of the required
full compliance date of January 1, 2011. During 2008, the matter was
resolved with the EPA and accordingly, $9.7 million of planned capital
spending was deferred to 2009.
Cash Flows
The following table sets forth our cash flows for the periods indicated below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
24,194
|
|
|
$
|
44,105
|
|
Investing activities
|
|
|
(26,156
|
)
|
|
|
(107,363
|
)
|
Financing activities
|
|
|
(3,368
|
)
|
|
|
28,947
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
cash equivalents
|
|
$
|
(5,330
|
)
|
|
$
|
(34,311
|
)
|
|
|
|
|
|
|
|
51
Cash Flows Provided by Operating Activities
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 increase in accrued income
taxes. Trade working capital for the three months ended March 31, 2008 resulted in a use of cash of
$67.5 million. For the three months ended March 31, 2008, accounts receivable increased $30.7
million, inventory increased by $31.6 and accounts payable decreased by $5.2 million.
Net cash flows provided by operating activities for the three months ended March 31, 2007 was
$44.1 million. The positive cash flow from operating activities during this period was primarily
the result of changes in other assets and liabilities offset by unfavorable changes in trade
working capital and other working capital. Net income for the period was not indicative of the
operating margins for the period. This was the result of the accounting treatment of our
derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash
Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,
Accounting
for Derivative Instruments and Hedging Activities.
Therefore, the net loss for the three months
ended March 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow
Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2007 (approximately
three years and three months years) and the NYMEX crack spread that is the basis for the underlying
swaps had increased during the period, the unrealized losses on the Cash Flow Swap significantly
decreased our net income over this period. The impact of these unrealized losses on the Cash Flow
Swap is apparent in the $129.3 million increase in the payable to swap counterparty. Adding to our
operating cash flow for the three months ended March 31, 2007 was a $68.0 million source of cash
related to a decrease in trade working capital. For the three months ended March 31, 2007, accounts
receivable decreased $44.6 million while inventory increased $23.0 million and accounts payable
increased $46.4 million. The change in trade working capital was primarily driven by the impact of
the refinery turnaround that began in February 2007. The primary use of cash during the period was
$41.3 million for deferred income taxes primarily the result of the unrealized loss on the Cash
Flow Swap.
Cash Flows Used in Investing Activities
Net cash used in investing activities for the three months ended March 31, 2008 was $26.2
million compared to $107.4 million for the three months ended March 31, 2007. The decrease in
investing activities for the three months ended March 31, 2008 as compared to the three months
ended March 31, 2007 was the result of decreased capital expenditures associated with various
capital projects that commenced in the first quarter of 2007 in conjunction with the refinery
turnaround.
Cash
Flows (Used in) Provided by Financing Activities
Net cash used for financing activities for the three months ended March 31, 2008 was $3.4
million as compared to net cash provided by financing activities of $29.0 million for the three
months ended March 31, 2007. During the three months ended March 31, 2008, we paid $1.2 million of
scheduled principal payments and deferred $2.1 million of initial public offering costs related to
CVR Partners, LP. For the three months ended March 31, 2007, the primary source of cash was the
result of borrowings drawn on our revolving credit facility.
52
Working Capital
Working capital at March 31, 2008, was $21.5 million, consisting of $622.5 million in current
assets and $601.0 million in current liabilities. Working
capital at December 31, 2007 was $10.7
million, consisting of $570.2 million in current assets and
$559.5 million in current liabilities.
In addition, we had available borrowing capacity under our revolving credit facility of $112.6 million at March 31, 2008.
Letters of Credit
Our revolving credit facility provides for the issuance of letters of credit. At March 31,
2008, there were $37.4 million of irrevocable letters of credit
outstanding, including $5.8 million in
support of certain environmental obligators and $31.6 million to secure transportation services
for crude oil.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of March 31, 2008.
Recent
Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement on
Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements
, which establishes a
framework for measuring fair value in GAAP and expands disclosures about fair value measurements.
SFAS 157 states that fair value is the price that would be received to sell the asset or paid to
transfer the liability (an exit price), not the price that would be paid to acquire the asset or
received to assume the liability (an entry price). The standards provisions for financial assets
and financial liabilities, which became effective January 1, 2008, had no material impact on the
Companys financial position or results of operations. At March 31, 2008, the only financial
assets and financial liabilities that are measured at fair value on a recurring basis are the
Companys derivative instruments. See Note 14, Fair Value
Measurements.
In
February 2008, the FASB issued FASB Staff Position 157-2 which defers the effective date of
SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized
or disclosed at fair value in an entitys financial statements on a recurring basis (at least
annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and
nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157
deferral provisions will not have a material impact on the Companys financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and
Financial Liabilities
. Under this standard, an entity is required to provide additional
information that
will assist investors and other users of financial information to more easily understand the
effect of the Companys choice to use fair value on its earnings. Further, the entity is required
to display the fair value of those assets and liabilities for which the Company has chosen to use
fair value on the face of the balance sheet. This standard does not eliminate the disclosure
requirements about fair value measurements included in SFAS No. 107,
Disclosures about Fair Value of
Financial Instruments
. The provisions of SFAS 159 were effective for CVR as of January 1, 2008.
The Company did not elect the fair value option under this standard
upon adoption. Therefore, the
adoption of SFAS 159 did not impact the Companys consolidated
financial statements as of the quarter
ended March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
. This statement
defines the acquirer as the entity that obtains control of one or more businesses in the business
combination, establishes the acquisition date as the date that the acquirer achieves control and
requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling
interest at their fair values as of the acquisition date. This statement also requires that
acquisition-related costs of the acquirer be recognized separately from the business combination
and will generally be expensed as incurred. CVR will be required to adopt this statement as of
January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business
combinations for which the acquisition date is on or after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated
Financial Statements an amendment of ARB No. 51.
SFAS 160 establishes accounting and reporting
standards for the non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest
in the consolidated entity that should be reported as equity in the consolidated financial
statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements
for existing minority interests. All other requirements of SFAS 160 must be applied prospectively.
SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the
potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In
March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB
Statement No. 133
. This statement will change the disclosure requirements for derivative
instruments and hedging activities. Entities are required to provide enhanced disclosures
about how and why an entity uses derivative instruments, how derivative instruments and
related hedged items are accounted for under Statement 133 and its related interpretations,
and how derivative instruments and related hedged items affect an entitys financial position,
net earnings, and cash flows. The Company will be required to adopt this statement as of January
1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Companys consolidated financial
statements.
Critical Accounting Policies
The Companys critical accounting policies are disclosed in the Critical Accounting Policies
section of our Annual Report on Form 10-K/A for the year ended December 31, 2007. No modifications
have been made to the Companys critical accounting policies.
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. None of our market risk sensitive
instruments are held for trading.
Commodity Price Risk
Our petroleum business, as a manufacturer of refined petroleum products, and the nitrogen
fertilizer business, as a manufacturer of nitrogen fertilizer products, all of which are
commodities, has exposure to market pricing for products sold in the future. In order to realize
value from our processing capacity, a positive spread between the cost of raw materials and the
value of finished products must be achieved (i.e., gross margin or crack spread). The physical
commodities that comprise our raw materials and finished goods are typically bought and sold at a
spot or index price that can be highly variable.
We use a crude oil purchasing intermediary which allows us to take title and price of our
crude oil at the refinery, as opposed to the crude origination point, reducing our risk associated
with volatile commodity prices by shortening the commodity conversion cycle time. The commodity
conversion cycle time refers to the time elapsed between raw material acquisition and the sale of
finished goods. In addition, we seek to reduce the variability of commodity price exposure by
engaging in hedging strategies and transactions that will serve to protect gross margins as
forecasted in the annual operating plan. Accordingly, we use financial derivatives to economically
hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard
to our hedging activities, we may enter into, or have entered into, derivative instruments which
serve to:
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|
|
lock in or fix a percentage of the anticipated or planned gross margin in future
periods when the derivative market offers commodity spreads that generate positive cash
flows
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|
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|
hedge the value of inventories in excess of minimum required inventories; and
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hedge the value of inventories held with respect to our rack marketing business.
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Further, we intend to engage only in risk mitigating activities directly related to our
business.
Basis Risk.
The effectiveness of our derivative strategies is dependent upon the correlation
of the price index utilized for the hedging activity and the cash or spot price of the physical
commodity for which price risk is being mitigated. Basis risk is a term we use to define that
relationship. Basis risk can exist due to several factors including time or location differences
between the derivative instrument and the underlying physical commodity.
53
Our selection of the appropriate index to utilize in a hedging strategy is a prime
consideration in our basis risk exposure.
Examples of our basis risk exposure are as follows:
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|
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Time Basis In entering over-the counter swap agreements, the settlement price of
the swap is typically the average price of the underlying commodity for a designated
calendar period. This settlement price is based on the assumption that the underlying
physical commodity will price ratably over the swap period. If the commodity does not
move ratably over the periods then weighted average physical prices will be weighted
differently than the swap price as the result of timing.
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|
|
|
Location Basis In hedging NYMEX crack spreads, we experience location basis as the
settlement of NYMEX refined products (related more to New York Harbor cash markets)
which may be different than the prices of refined products in our Group 3 pricing area.
|
Price
and Basis Risk Management Activities.
The most significant
derivative position we have is our Cash Flow Swap. The Cash Flow Swap, for which the
underlying commodity is the crack spread, enabled us to lock in a margin on the spread between the
price of crude oil and price of refined products at the execution
date of the agreement. We may look for opportunities to reduce
the effective position of the Cash Flow Swap by buying either
exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the
form of commodity price swaps. In addition, we may sell forward
crack spreads when opportunities exist to lock in a margin.
In the event our inventories exceed our target base level of inventories, we may enter into
commodity derivative contracts to manage our price exposure to our inventory positions that are in
excess of our base level. Excess inventories are typically the result of plant operations such as
a turnaround or other plant maintenance. The commodity derivative contracts are either
exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the
form of commodity price swaps.
To reduce the basis risk between the price of products for Group 3 and that of the NYMEX
associated with selling forward derivative contracts for NYMEX crack spreads, we may enter into
basis swap positions to lock the price difference. If the difference between the price of products
on the NYMEX and Group 3 (or some other price benchmark as we may deem appropriate) is different
than the value contracted in the swap, then we will receive from or owe to the counterparty the
difference on each unit of product contracted in the swap, thereby completing the locking of our
margin. An example of our use of a basis swap is in the winter heating oil season. The risk
associated with not hedging the basis when using NYMEX forward contracts to fix future margins is
if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or
decreases then we would be in a position to lose money on the derivative position while not earning
an offsetting additional margin on the physical position based on the Group 3 pricing.
As of March 31, 2008, a $1.00 change in quoted futures price for the crack spreads described
in the first bullet point would result in a $36.2 million change to the fair value of the
derivative commodity position and the same change in net income.
Interest Rate Risk
As of March 31, 2008, all of our $488.0 million of outstanding term debt was at floating
rates. An increase of 1.0% in the LIBOR rate would result in an increase in our interest expense
of approximately $4.9 million per year.
In an effort to mitigate the interest rate risk highlighted above and as required under our
then-existing first and second lien credit agreements, we entered into several interest rate swap
agreements in 2005. These swap agreements were entered into with counterparties that we believe to
be creditworthy. Under the swap agreements, we pay fixed rates and receive floating rates based on
the three-month LIBOR rates, with payments calculated on the notional amounts set for in the table
below. The interest rate swaps are settled quarterly and marked to market at each reporting date.
54
|
|
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|
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Effective
|
|
Termination
|
|
Fixed
|
Notional Amount
|
|
Date
|
|
Date
|
|
Rate
|
$250.0 million
|
|
|
March 31, 2008
|
|
|
|
March 30, 2009
|
|
|
|
4.195
|
%
|
$180.0 million
|
|
|
March 31, 2009
|
|
|
|
March 30, 2010
|
|
|
|
4.195
|
%
|
$110.0 million
|
|
|
March 31, 2010
|
|
|
|
June 29, 2010
|
|
|
|
4.195
|
%
|
We have determined that these interest rate swaps do not qualify as hedges for hedge
accounting purposes. Therefore, changes in the fair value of these interest rate swaps are
included in income in the period of change. Net realized and unrealized gains or losses are
reflected in the gain (loss) for derivative activities at the end of each period. For the three
months ended March 31, 2008, we had $5.6 million of realized and unrealized losses on these
interest rate swaps and for the three months ended March 31, 2007, we had $0.6 million of realized
and unrealized losses.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures (Disclosure Controls) to ensure that
information required to be disclosed in the Companys reports filed under the Securities Exchange
Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods
specified in the SECs rules and forms. Disclosure Controls are also designed to ensure that such
information is accumulated and communicated to management, including the Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions regarding required
disclosure. Our Disclosure Controls were designed to provide reasonable assurance that the controls
and procedures would meet their objectives. Our management, including the Chief Executive Officer
and Chief Financial Officer, does not expect that our Disclosure Controls will prevent all error
and fraud. A control system, no matter how well designed and operated, can provide only reasonable
assurance of achieving the designed control objectives and management is required to apply its
judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because
of the inherent limitations in all control systems, no evaluation of controls can provide absolute
assurance that all control issues and instances of fraud, if any, within the Company have been
detected. These inherent limitations include the realities that judgments in decision-making can be
faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls
can be circumvented by the individual acts of some persons, by collusions of two or more people, or
by management override of the control. Because of the inherent limitations in a cost-effective,
maturing control system, misstatements due to error or fraud may occur and not be detected.
At March 31, 2008, we identified material weaknesses in our internal controls relating to the calculation
of the cost of crude oil purchased by us and associated financial transactions.
Specifically, our policies and procedures for estimating the cost of crude oil and reconciling these
estimates to vendor invoices were not effective. Additionally, our supervision and review of this estimation and reconciliation process
was not operating at a level of detail adequate to identify the deficiencies in the process.
Management has concluded that these deficiencies are material weaknesses. A material weakness is a deficiency, or a combination
of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material
misstatement of the Companys annual or interim financial statements will not be prevented or detected on a timely basis.
In order to remediate the material weaknesses described above, our management is in the process of designing, implementing
and enhancing controls to ensure the proper accounting for the calculation of the cost of crude oil. These remedial actions
include, among other things, (1) centralizing all crude oil cost accounting functions, (2) adding additional layers of accounting
review with respect to our crude oil cost accounting and (3) adding additional layers of business review with respect to the
computation of our crude oil costs. However, because of the timing of the filing of our Annual Report on Form 10-K/A for the year
ended December 31, 2007, and the period covered by this Form 10-Q, we had not commenced our remediation of these
material weaknesses at March 31, 2008.
As of the end of the period covered by this Form 10-Q, we evaluated the effectiveness of the
design and operation of our Disclosure Controls. The evaluation of our Disclosure Controls was
performed under the supervision and with the participation of management, including our Chief
Executive Officer and Chief Financial Officer, and included consideration of the material
weaknesses described above. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have
concluded that our Disclosure Controls and procedures were not effective as of the end of the
period covered by this Quarterly Report on Form 10-Q because of the material weakness described
above.
Changes in Internal Control Over Financial Reporting
No changes in our internal control over
financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) occurred during the first quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting. However, we are currently taking remedial actions to address the material weaknesses described above under Evaluation of Disclosure Controls and Procedures.
55
Part II. Other Information
Item 1A. Risk Factors
There are no material changes to the risk factors previously disclosed in our 2007 Form 10-K/A
for the year ended December 31, 2007 under Part IItem 1A. Risk Factors.
56
Item 6. Exhibits
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Number
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Exhibit Title
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10.1
|
|
Consulting Agreement, dated May 2, 2008, by and between General
Wesley Clark and CVR Energy, Inc.
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31.1
|
|
Rule 13a14(a)/15d14(a) Certification of Chief Executive Officer
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31.2
|
|
Rule 13a14(a)/15d14(a) Certification of Chief Financial Officer
|
|
|
|
32.1
|
|
Section 1350 Certification of Chief Executive Officer and Chief Financial Officer
|
57
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized,
this fifteenth day of May 2008.
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|
|
|
|
|
CVR Energy, Inc.
|
|
|
By:
|
/s/ John J. Lipinski
|
|
|
|
Chief Executive Officer
|
|
|
|
(Principal Executive Officer)
|
|
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|
|
|
|
By:
|
/s/ James T. Rens
|
|
|
|
Chief Financial Officer
|
|
|
|
(Principal Financial Officer)
|
|
|
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