FORM 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2009
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 001-33492

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		61-1512186
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2277 Plaza Drive, Suite 500		77479
Sugar Land, Texas (Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:

(281) 207-3200

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ

There were 86,244,245 shares of the registrant’s common stock outstanding at May 5, 2009.

PART I. FINANCIAL INFORMATION


ITEM 1.	*FINANCIAL STATEMENTS*

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,		December 31,
	2009		2008
	(unaudited)
	(in thousands, except
	share data)

ASSETS
Current assets:
Cash and cash equivalents	$	28,427	$	8,923
Restricted cash		—		34,560
Accounts receivable, net of allowance for doubtful accounts of $4,313 and $4,128, respectively		65,609		33,316
Inventories		173,056		148,424
Prepaid expenses and other current assets		22,321		37,583
Receivable from swap counterparty		18,355		32,630
Insurance receivable		—		11,756
Income tax receivable		16,074		40,854
Deferred income taxes		31,000		25,365

Total current assets		354,842		373,411
Property, plant, and equipment, net of accumulated depreciation		1,170,328		1,178,965
Intangible assets, net		402		410
Goodwill		40,969		40,969
Deferred financing costs, net		3,348		3,883
Receivable from swap counterparty		2,433		5,632
Insurance receivable		1,000		1,000
Other long-term assets		2,481		6,213

Total assets	$	1,575,803	$	1,610,483

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	4,813	$	4,825
Note payable and capital lease obligation		7,821		11,543
Payable to swap counterparty		15,714		62,375
Accounts payable		76,713		105,861
Personnel accruals		13,776		10,350
Accrued taxes other than income taxes		20,498		13,841
Deferred revenue		8,418		5,748
Other current liabilities		32,162		30,366

Total current liabilities		179,915		244,909
Long-term liabilities:
Long-term debt, net of current portion		478,304		479,503
Accrued environmental liabilities, net of current portion		3,940		4,240
Deferred income taxes		289,695		289,150
Other long-term liabilities		1,263		2,614

Total long-term liabilities		773,202		775,507
Commitments and contingencies
Equity:
CVR stockholders’ equity:
Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,243,745 shares issued and outstanding		862		862
Additional paid-in-capital		443,128		441,170
Retained earnings		168,096		137,435

Total CVR stockholders’ equity		612,086		579,467

Noncontrolling interest in subsidiary		10,600		10,600

Total equity		622,686		590,067

Total liabilities and equity	$	1,575,803	$	1,610,483

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)
	(in thousands, except share data)

Net sales	$	609,395		$	1,223,003
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		421,605			1,036,194
Direct operating expenses (exclusive of depreciation and amortization)		56,234			60,556
Selling, general and administrative expenses (exclusive of depreciation and amortization)		19,506			13,497
Net costs associated with flood		181			5,763
Depreciation and amortization		20,909			19,635

Total operating costs and expenses		518,435			1,135,645

Operating income		90,960			87,358
Other income (expense):
Interest expense and other financing costs		(11,470	)		(11,298	)
Interest income		14			702
Gain (loss) on derivatives, net		(36,861	)		(47,871	)
Other income, net		25			179

Total other income (expense)		(48,292	)		(58,288	)

Income before income tax expense		42,668			29,070
Income tax expense		12,007			6,849

Net income	$	30,661		$	22,221

Basic earnings per share	$	0.36		$	0.26
Diluted earnings per share	$	0.36		$	0.26
Weighted average common shares outstanding:
Basic		86,243,745			86,141,291
Diluted		86,322,411			86,158,791

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)
	(in thousands)

Cash flows from operating activities:
Net income	$	30,661		$	22,221
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,909			19,635
Provision for doubtful accounts		185			206
Amortization of deferred financing costs		535			495
Loss on disposition of fixed assets		8			16
Share-based compensation		3,854			(383	)
Changes in assets and liabilities:
Restricted cash		34,560			—
Accounts receivable		(32,478	)		(30,693	)
Inventories		(24,632	)		(31,642	)
Prepaid expenses and other current assets		11,580			75
Insurance receivable		—			(1,915	)
Insurance proceeds from flood		11,756			1,500
Other long-term assets		3,622			(3,159	)
Accounts payable		(25,392	)		(5,166	)
Accrued income taxes		24,780			5,201
Deferred revenue		2,670			16,623
Other current liabilities		9,983			5,315
Payable to swap counterparty		(29,187	)		20,750
Accrued environmental liabilities		(300	)		80
Other long-term liabilities		(1,351	)		3,325
Deferred income taxes		(5,090	)		1,710

Net cash provided by operating activities		36,673			24,194

Cash flows from investing activities:
Capital expenditures		(15,918	)		(26,156	)

Net cash used in investing activities		(15,918	)		(26,156	)

Cash flows from financing activities:
Revolving debt payments		(72,200	)		(123,000	)
Revolving debt borrowings		72,200			123,000
Principal payments on long-term debt		(1,211	)		(1,223	)
Payment of capital lease obligation		(40	)		—
Deferred costs of CVR Partners, LP initial public offering		—			(2,145	)

Net cash used in financing activities		(1,251	)		(3,368	)

Net increase (decrease) in cash and cash equivalents		19,504			(5,330	)
Cash and cash equivalents, beginning of period		8,923			30,509

Cash and cash equivalents, end of period	$	28,427		$	25,179

Supplemental disclosures:
Cash paid for income taxes, net of refunds (received)	$	(7,683	)	$	(63	)
Cash paid for interest, net of capitalized interest of $413 and $1,118 in 2009 and 2008, respectively		9,102			10,723
Non-cash investing and financing activities:
Accrual of construction in progress additions		(3,756	)		(6,237	)

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2009
(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 prior to October 16, 2007 (the date of the restructuring as further discussed in this Note) and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries.

The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer in the mid-continental United States. In addition, the Company, through its majority-owned subsidiaries, acts as an independent producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”).

CVR is a controlled company under the rules and regulations of the New York Stock Exchange where its shares are traded under the symbol “CVI.” As of March 31, 2009, approximately 73% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities (“GS” or “Goldman Sachs Funds”) and Kelso Investment Associates VII, L.P. and related entities (“Kelso” or “Kelso Funds”).

Nitrogen Fertilizer Limited Partnership

In conjunction with the consummation of CVR’s initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizer, LLC (“CRNF”), its nitrogen fertilizer business, to a newly created limited partnership, CVR Partners, LP (the “Partnership”), in exchange for a managing general partner interest (“managing GP interest”), a special general partner interest (“special GP interest,” represented by special GP units) and a de minimis limited partner interest (“LP interest,” represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to Coffeyville Acquisition III LLC (“CALLC III”) an entity owned by it’s controlling stockholders and senior management, at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing GP interest was $10,600,000. This interest has been classified as a noncontrolling interest included as a separate component of equity in the Consolidated Balance Sheets at March 31, 2009 and December 31, 2008.

CVR owns all of the interests in the Partnership (other than the managing GP interest and the associated incentive distribution rights (“IDRs”)) and is entitled to all cash distributed by the Partnership except with respect to IDRs. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the Partnership’s partnership agreement, generated by the Partnership through December 31, 2009 has been distributed in respect of the units held by CVR and any common units issued by the Partnership if it elects to pursue an initial public offering. In addition, the Partnership and its subsidiaries

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

are currently guarantors under the credit facility of Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR. There will be no distributions paid with respect to the IDRs for so long as the Partnership or its subsidiaries are guarantors under the credit facility.

The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR, the Partnership, and the managing general partner also entered into a number of agreements to regulate certain business relations between the parties.

At March 31, 2009, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing GP interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing GP interest and the IDRs.

In accordance with the Contribution, Conveyance, and Assumption Agreement, by and between the Partnership and the partners, dated as of October 24, 2007, if an initial private or public offering of the Partnership is not consummated by October 24, 2009, the managing general partner of the Partnership can require the Company to purchase the managing GP interest. This put right expires on the earlier of (1) October 24, 2012 or (2) the closing of the Partnership’s initial private or public offering. If the Partnership’s initial private or public offering is not consummated by October 24, 2012, the Company has the right to require the managing general partner to sell the managing GP interest to the Company. This call right expires on the closing of the Partnership’s initial private or public offering. In the event of an exercise of a put right or a call right, the purchase price will be the fair market value of the managing GP interest at the time of the purchase determined by an independent investment banking firm selected by the Company and the managing general partner.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries. The ownership interests of noncontrolling investors in its subsidiaries are classified as a noncontrolling interest included as a separate component of equity for all periods presented. All significant intercompany account balances and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under GAAP have been condensed or omitted pursuant to SEC rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2008 audited consolidated financial statements and notes thereto, included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2008, which was filed with the SEC on March 13, 2009.

In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of March 31, 2009 and December 31, 2008, the results of operations for the three months ended March 31, 2009 and 2008, and the cash flows for the three months ended March 31, 2009 and 2008.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2009 or any other interim period. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

As a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, on January 1, 2009, the noncontrolling interest for the year ended December 31, 2008 has been properly reclassified to be included in the Company’s equity section of the Consolidated Balance Sheets.


(2)	Recent Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) Emerging Issues Task Force (“EITF”) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which became effective January 1, 2009 and is to be applied retrospectively. Under the FSP, unvested share-based payment awards which receive non-forfeitable dividend rights, or dividend equivalents are considered participating securities and are now required to be included in computing earnings per share under the two class method. As required the Company adopted this statement as of January 1, 2009. Based upon the nature of the Company’s share-based payment awards, it has been determined that these awards are not participating securities and therefore the FSP currently has no impact on the Company’s earnings per share calculations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedge items affect an entity’s financial position, net earnings, and cash flows. As required, the Company adopted this statement as of January 1, 2009. As a result of the adoption, the Company provided additional disclosures regarding its derivative instruments in notes to the condensed consolidated financial statements. There is no impact on the financial position or results of operations of the Company as a result of this adoption.

In February 2008, the FASB issued FASB Staff Position 157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). As required, the Company adopted SFAS 157 as of January 1, 2009. The adoption of SFAS 157 did not impact the Company’s financial position or earnings.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing noncontrolling interests. All other requirements of SFAS 160 must be applied prospectively. The Company adopted SFAS 160 effective January 1, 2009, and as a result has classified the noncontrolling interest (previously minority interest) as a separate component of equity for all periods presented.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(3)	Share-Based Compensation

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by CALLC, a limited liability company. Management of CVR holds an equity interest in CALLC. CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering, CALLC was split into two entities: CALLC and CALLC II. In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. CALLC was historically the primary reporting company and CVR’s predecessor. In addition, in connection with the transfer of the managing GP interest of the Partnership to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with SFAS No. 123(R), Share-Based Payments and EITF Issue No. 00-12, Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee (“EITF 00-12”). CVR has been allocated non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.

In accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. In accordance with EITF 00-12, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance in EITF Issue No. 96-18, Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires remeasurement at each reporting period through the performance commitment period, or in CVR’s case, through the vesting period.

At March 31, 2009, the value of the override units of CALLC and CALLC II was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are vested.

The estimated fair value of the override units of CALLC III has been determined using a probability-weighted expected return method which utilizes CALLC III’s cash flow projections, which are representative of the nature of interests held by CALLC III in the Partnership.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III. Compensation expense amounts are disclosed in thousands.


						*Compensation Expense Increase
						(Decrease) for the
	Benchmark					Three Months Ended
	Value		Awards			March 31,
Award Type	(per Unit)		Issued		Grant Date	2009		2008

Override Operating Units(a)	$	11.31		919,630	June 2005	$	584	$	(558	)
Override Operating Units(b)	$	34.72		72,492	December 2006		24		6
Override Value Units(c)	$	11.31		1,839,265	June 2005		1,187		533
Override Value Units(d)	$	34.72		144,966	December 2006		61		91
Override Units(e)	$	10.00		138,281	October 2007		—		—
Override Units(f)	$	10.00		642,219	February 2008		1		—

					Total	$	1,857	$	72


*		As CVR’s common stock price increases or decreases, compensation expense increases or is reversed in correlation with the calculation of the fair value under the probability-weighted expected return method.

Valuation Assumptions

Significant assumptions used in the valuation of the Override Operating Units (a) (b) were as follows:


	(a) Override Operating Units		(b) Override Operating Units
	March 31,		March 31,
	2009	2008	2009	2008

Estimated forfeiture rate	None	None	None	None
CVR closing stock price	$5.54	$23.03	$5.54	$23.03
Estimated fair value	$10.77 per unit	$47.88 per unit	$2.62 per unit	$28.68 per unit
Marketability and minority interest discounts	20% discount	15% discount	20% discount	15% discount
Volatility	68.2%	N/A	68.2%	N/A

On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. The explicit service period for override operating unit recipients is based on the forfeiture schedule below. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture as follows:


Minimum	Forfeiture
Period Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant assumptions used in the valuation of the Override Value Units (c) (d) were as follows:


	(c) Override Value Units		(d) Override Value Units
	March 31,		March 31,
	2009	2008	2009	2008

Estimated forfeiture rate	None	None	None	None
Derived service period	6 years	6 years	6 years	6 years
CVR closing stock price	$5.54	$23.03	$5.54	$23.03
Estimated fair value	$5.17 per unit	$47.88 per unit	$2.62 per unit	$28.68 per unit
Marketability and minority interest discounts	20% discount	15% discount	20% discount	15% discount
Volatility	68.2%	N/A	68.2%	N/A

Unless the compensation committee of the board of directors of CVR takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason, except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture as follows:


Minimum	Forfeiture
Period Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

(e) Override Units — In accordance with SFAS 123(R), Share-Based Compensation, using a binomial and a probability weighted expected return method which utilized CALLC III’s cash flows projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. In accordance with EITF 00-12, as a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. As of March 31, 2009 these units were fully vested. Significant assumptions used in the valuation were as follows:


Estimated forfeiture rate		None
Grant date valuation		$0.02 per unit
Marketability and minority interest discount		15% discount
Volatility		34.7%

(f) Override Units — In accordance with SFAS 123(R), Share-Based Compensation, using a probability weighted expected return method which utilized CALLC III’s cash flows projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. In accordance with EITF 00-12, as a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:


	March 31,
	2009	2008

Estimated forfeiture rate	None	None
Derived Service Period	Based on forfeiture schedule	Based on forfeiture schedule
Estimated fair value	$0.02 per unit	$0.004 per unit
Marketability and minority interest discount	20% discount	15% discount
Volatility	47.0%	36.2%

At March 31, 2009, assuming no change in the estimated fair value at March 31, 2009, there was approximately $4,161,000 of unrecognized compensation expense related to non-voting override units. This is expected to be recognized over a remaining period of approximately three years as follows (in thousands):


	Override		Override
	Operating		Value
	Units		Units

Nine months ending December 31, 2009	$	490	$	1,164
Year ending December 31, 2010		225		1,545
Year ending December 31, 2011		—		737

	$	715	$	3,446

Phantom Unit Plans

CVR, through a wholly-owned subsidiary, has two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points have rights to receive distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units receive distributions. There are no other rights or guarantees, and the plan expires on July 25, 2015 or at the discretion of the compensation committee of the board of directors. As of March 31, 2009, the issued Profits Interest (combined phantom points and override units) represented 15% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was comprised of approximately 11.1% and approximately 3.9% of override interest and phantom interest, respectively. In accordance with SFAS 123(R), the expense associated with these awards for 2009 is based on the current fair value of the awards which was derived from a probability weighted expected return method. The probability weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled. Based upon this methodology, the service phantom interest and performance phantom interest were valued at $10.77 and $5.17 per point, respectively, at March 31, 2009. In accordance with SFAS 123(R), using the March 31, 2008 CVR stock closing price to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were both valued at $47.88 per point. CVR has recorded approximately $5,778,000 and $3,882,000 in personnel accruals as of March 31, 2009 and December 31, 2008, respectively. Compensation expense for the three months ended March 31, 2009 and 2008 related to the Phantom Unit Plans was $1,896,000 and $(547,000), respectively.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At March 31, 2009, assuming no change in the estimated fair value at March 31, 2009, there was approximately $1,493,000 of unrecognized compensation expense related to the Phantom Unit Plans. This is expected to be recognized over a remaining period of approximately three years.

Long Term Incentive Plan

CVR has a Long Term Incentive Plan which permits the grant of options, stock appreciation rights, or SARS, non-vested shares, non-vested share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock).

During the first quarter of 2009 there were no grants, forfeitures or vesting of stock options or non-vested shares.

As of March 31, 2009, there was approximately $328,000 of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately two and one-half years. Compensation expense recorded for the three months ended March 31, 2009 and 2008 related to the non-vested stock was $67,000 and $56,000, respectively. Compensation expense recorded for the three months ended March 31, 2009 and 2008 related to the stock options was $34,000 and $36,000, respectively.


(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-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

Inventories consisted of the following (in thousands):


	March 31,		December 31,
	2009		2008

Finished goods	$	71,674	$	61,008
Raw materials and catalysts		64,238		45,928
In-process inventories		9,385		14,376
Parts and supplies		27,759		27,112

	$	173,056	$	148,424

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(5)	Property, Plant, and Equipment

A summary of costs for property, plant, and equipment is as follows (in thousands):


	March 31,		December 31,
	2009		2008

Land and improvements	$	17,384	$	17,383
Buildings		22,852		22,851
Machinery and equipment		1,297,132		1,288,782
Automotive equipment		8,877		7,825
Furniture and fixtures		7,907		7,835
Leasehold improvements		1,081		1,081
Construction in progress		56,563		53,927

		1,411,796		1,399,684
Accumulated depreciation		241,468		220,719

	$	1,170,328	$	1,178,965

Capitalized interest recognized as a reduction in interest expense for the three months ended March 31, 2009 and March 31, 2008 totaled approximately $413,000 and $1,118,000, respectively. Land and buildings that are under a capital lease obligation approximated $4,827,000 as of March 31, 2009 and December 31, 2008. Amortization of assets held under capital leases is included in depreciation expense.


(6)	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 $711,000 and $600,000 for the three months ended March 31, 2009 and 2008, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses excludes depreciation and amortization of $19,742,000 and $18,703,000 for the three months ended March 31, 2009 and 2008, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of $456,000 and $332,000 for the three months ended March 31, 2009 and 2008, respectively.


(7)	Note Payable and Capital Lease Obligation

The Company entered into an insurance premium finance agreement with Cananwill, Inc. in July 2008 to finance a portion of the purchase of its property, liability, cargo and terrorism policies. The original balance of the note provided by the Company under such agreement was $10,000,000. This note is to be repaid in equal installments with the final payment due in June 2009. As of March 31, 2009 and December 31, 2008, the Company owed $3,750,000 and $7,500,000, respectively, related to this note.

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease has an initial lease term of one year with an option to renew for three additional one-year periods. The Company has the option to purchase the property during the initial lease term or during the renewal periods if the lease is renewed. In connection with the capital lease the Company recorded a capital

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

asset and capital lease obligation of $4,827,000. The capital lease obligation was $4,071,000 and $4,043,000 as of March 31, 2009 and December 31, 2008, respectively.


(8)	Flood, Crude Oil Discharge and Insurance Related Matters

For the three months ended March 31, 2009 and 2008, the Company recorded pretax expenses, net of anticipated insurance recoveries of $181,000 and $5,763,000, respectively, associated with the June/July 2007 flood and associated crude oil discharge. The costs are reported in net costs associated with flood in the Consolidated Statements of Operations. Total accounts receivable from insurance was $1,000,000 at March 31, 2009 and $12,756,000 as of December 31, 2008. With the final insurance proceeds received under the Company’s property insurance policy and builders’ risk policy during the first quarter of 2009, in the amount of $11,756,000, all property insurance claims and builders’ risk claims were fully settled with all remaining claims closed. The receivable balance at March 31, 2009 is associated with the crude oil discharge. See Note 11 (“Commitments and Contingent Liabilities”) for additional information regarding environmental and other contingencies related to the crude oil discharge that occurred on July 1, 2007.

As of March 31, 2009, the remaining receivable from insurers was not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset. Management believes the recovery of the receivable from the insurance carriers is probable.


(9)	Income Taxes

As of March 31, 2009, the Company did not have any unrecognized tax benefits and did not have an accrual for any amounts for interest or penalties related to uncertain tax positions. The Company’s accounting policy with respect to interest and penalties related to tax uncertainties is to classify these amounts as income taxes.

CVR and its subsidiaries file U.S. federal and various state income and franchise tax returns. The Company’s U.S. federal and state tax years subject to examination as of March 31, 2009 are 2005 to 2008.

The Company’s effective tax rate for the three months ended March 31, 2009 and 2008 was 28.1% and 23.6%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 39.7%. The effective tax rate is lower than the expected statutory tax rate for the three months ended March 31, 2009 and 2008, respectively, due primarily to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(10)	Earnings Per Share

Basic and diluted earnings per share are computed by dividing net income by weighted average common shares outstanding. The components of the basic and diluted earnings per share calculation are as follows:


	For the Three Months
	Ended March 31,
	2009		2008
	(in thousands, except share data)

Net income	$	30,661	$	22,221
Weighted average common shares outstanding		86,243,745		86,141,291
Effect of dilutive securities:
Non-vested common stock		78,666		17,500

Weighted average common shares outstanding assuming dilution		86,322,411		86,158,791

Basic earnings per share	$	0.36	$	0.26
Diluted earnings per share	$	0.36	$	0.26

Outstanding stock options totaling 32,350 and 18,900 common shares were excluded from the diluted earnings per share calculation for the three months ended March 31, 2009 and 2008, respectively, as they were antidilutive.


(11)	Commitments and Contingent Liabilities

The minimum required payments for the Company’s lease agreements and unconditional purchase obligations are as follows (in thousands):


	Operating		Unconditional
	Leases		Purchase Obligations

Nine months ending December 31, 2009	$	3,369	$	22,311
Year ending December 31, 2010		3,783		36,044
Year ending December 31, 2011		2,377		57,407
Year ending December 31, 2012		1,983		54,689
Year ending December 31, 2013		1,089		54,577
Thereafter		270		360,735

	$	12,871	$	585,763

The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. In the normal course of business, the Company also has long-term commitments to purchase services such as natural gas, electricity, water and transportation services. For the three months ended March 31, 2009 and 2008, lease expense totaled $1,190,000 and $1,071,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at the Company’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.

From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the Company has accrued for losses for which it may ultimately be responsible. It is possible that management’s 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

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

Crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In connection with that discharge, the Company received in May 2008 notices of claims from sixteen private claimants under the Oil Pollution Act in aggregate amount of approximately $4,393,000. In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita. The Company believes that the resolution of these claims will not have a material adverse effect on the consolidated financial statements.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the “Consent Order”) with the Environmental Protection Agency (“EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the Company’s 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 Company’s refinery. The substantial majority of all known remedial actions were completed by January 31, 2009. The Company is currently preparing its final report to the EPA to satisfy the final requirement of the Consent Order. The Company anticipates that the final report will be provided by June 2009, with no further requirements resulting from the review of the report that could be material to the Company’s business, financial condition, or results of operations.

As of March 31, 2009, the total gross costs recorded associated with remediation and third party property damage as a result of the crude oil discharge approximated $54,327,000. The Company has not estimated or accrued for any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from lawsuits related to the June/July 2007 flood as management does not believe any such fines, penalties or lawsuits would be material nor can be estimated.

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and property damage claims. On July 10, 2008, the Company filed two lawsuits in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the June/July 2007 flood and crude oil discharge. The Company’s excess environmental liability insurance carrier has asserted that its pollution liability claims are for “cleanup,” which is not covered by such policy, rather than for “property damage,” which is covered to the limits of the policy. While the Company will vigorously contest the excess carrier’s position, it contends that if that position were upheld, the umbrella Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. Although the Company believes that certain amounts under the environmental and liability insurance policies will be recovered, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims.

The lawsuit with the insurance carriers under the environmental liability and comprehensive general liability policies remains the only unsettled lawsuit with the insurance carriers. The property insurance lawsuit has been settled and dismissed.

Environmental, Health, and Safety (“EHS”) Matters

Coffeyville Resources Refining & Marketing, LLC (“CRRM”), Coffeyville Resources Crude Transportation, LLC (“CRCT”) and Coffeyville Resources Terminal, LLC (“CRT”), all of which are wholly-owned subsidiaries of CVR, and CRNF are subject to various stringent federal, state, and local EHS rules and

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries. Such liabilities include estimates of the Company’s share of costs attributable to potentially responsible parties which are insolvent or otherwise unable to pay. EHS liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.

CRRM, CRNF, CRCT and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under the Resource Conservation and Recovery Act (“RCRA”) to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). In 2005, CRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (“VCPRP”) to address a reported release of urea ammonium nitrate (“UAN”) at its UAN loading rack. As of March 31, 2009 and December 31, 2008, environmental accruals of $6,541,000 and $6,924,000, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, including amounts totaling $2,601,000 and $2,684,000, respectively, included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at March 31, 2009 and December 31, 2008, respectively. The accruals include estimated closure and post-closure costs of $1,545,000 and $1,124,000 for two landfills at March 31, 2009 and December 31, 2008, respectively. The estimated future payments for these required obligations are as follows (in thousands):


	Amount

Nine months ending December 31, 2009	$	2,348
Year ending December 31, 2010		1,013
Year ending December 31, 2011		516
Year ending December 31, 2012		313
Year ending December 31, 2013		313
Thereafter		2,682

Undiscounted total		7,185
Less amounts representing interest at 2.37%		644

Accrued environmental liabilities at March 31, 2009	$	6,541

Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. In February 2004, the EPA granted the Company approval under a “hardship waiver” that would defer meeting final Ultra Low Sulfur Gasoline (“ULSG”) standards and Ultra Low Sulfur Diesel (“ULSD”) requirements. The hardship waiver was revised at CRRM’s request on September 25, 2008. The

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company met the conditions of the “hardship waiver” related to the ULSD requirements in late 2006 and is continuing its work related to meeting its compliance date with ULSG standards in accordance with the revised hardship waiver. Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $13,787,000 during 2008, approximately $16,800,000 during 2007 and $79,033,000 during 2006. Based on information currently available, CRRM and CRT anticipate spending approximately $24.5 million in 2009, $20.2 million in 2010, and $5.0 million in 2011 to comply with ULSG requirements and improve operational reliability. The entire amounts are expected to be capitalized. For the three-months ended March 31, 2009 and 2008, CVR has spent $3,450,000 and $1,941,000, respectively.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended March 31, 2009 and 2008, capital environmental expenditures were $3,963,000 and $15,473,000, respectively. These expenditures were incurred to improve the environmental compliance and efficiency of the operations.

CRRM, CRNF, CRCT and CRT believe they are in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the Company’s business, financial condition, or results of operations.


(12)	Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value, and required additional disclosures about fair value measurements. SFAS 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

SFAS 157 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). SFAS 157 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:


	•	Level 1— Quoted prices in active market for identical assets and liabilities

	•	Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)

	•	Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of March 31, 2009 (in thousands):


	Level 1		Level 2			Level 3		Total

Receivable from swap counterparty — current (Cash Flow Swap)		—	$	18,355			—	$	18,355
Receivable from swap counterparty — non-current (Cash Flow Swap)		—		2,433			—		2,433
Other current liabilities (Interest Rate Swap)		—		(5,018	)		—		(5,018	)
Other long-term liabilities (Interest Rate Swap)		—		(1,254	)		—		(1,254	)

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of March 31, 2009, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 13 (“Derivative Financial Instruments”) for a discussion of the Cash Flow Swap and Interest Rate Swap. The Company’s derivative contracts giving rise to assets or liabilities under Level 2 are valued using pricing models based on other significant observable inputs.


(13)	Derivative Financial Instruments

Gain (loss) on derivatives, net consisted of the following (in thousands):


	Three Months Ended
	March 31,
	2009			2008

Realized gain (loss) on cash flow swap agreements	$	(15,714	)	$	(21,516	)
Unrealized gain (loss) on cash flow swap agreements		(20,114	)		(13,907	)
Realized gain (loss) on other agreements		(1,003	)		(7,993	)
Unrealized gain (loss) on other agreements		163			1,157
Realized gain (loss) on interest rate swap agreements		(1,710	)		522
Unrealized gain (loss) on interest rate swap agreements		1,517			(6,134	)

Total gain (loss) on derivatives, net	$	(36,861	)	$	(47,871	)

CVR is subject to price fluctuations caused by supply and demand conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Company may enter into various derivative transactions. The Company, as further described below, entered into certain commodity derivative contracts (i.e., the Cash Flow Swap) and an interest rate swap as required by the long-term debt agreements. The commodity derivative is for the purpose of managing price risk on crude oil and finished goods and the interest rate swap is for the purpose of managing interest rate risk.

CVR has adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities which imposes extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative instruments, such as exchange-traded crude oil futures, certain over-the-counter forward swap agreements and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Consolidated Statements of Operations.

Cash Flow Swap

At March 31, 2009, CVR’s Petroleum Segment held commodity derivative contracts (the “Cash Flow Swap”) for the period from July 1, 2005 to June 30, 2010 with a related party. See Note 14 (“Related Party Transactions”). The Cash Flow Swap agreements were originally executed on June 16, 2005 in conjunction with the acquisition by CALLC of all the outstanding stock held by Coffeyville Group Holdings, LLC and were required under the terms of the long-term debt agreements. The notional quantities on the date of execution were 100,911,000 barrels of crude oil, 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil. The Cash Flow Swap agreements were executed at the prevailing market rate at the time of execution. At March 31, 2009, the notional open amounts under the swap agreements were 11,846,250 barrels of crude oil, 248,771,250 gallons of unleaded gasoline and 248,771,250 gallons of heating oil. These positions are marked to market at each reporting date and result in unrealized gains (losses) using a valuation method that utilizes quoted market prices and assumptions. All unrealized gains and losses are currently recognized in the Company’s Consolidated Statements of Operations. The realized gain or loss from

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Cash Flow Swap is settled quarterly. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.

As noted above, the counterparty to the Company’s Cash Flow Swap agreement is a related party. As prudent, the Company from time-to-time considers counterparty credit risk. The maximum amount of loss due to the credit risk of the counterparty, should the counterparty fail to perform according to the terms of the contracts, is contingent upon the unsettled portion of the hedge, if any. For the Company to be “at-risk” the unsettled portion of the hedge would need to be in a net receivable position. Based upon the quoted market prices as of March 31, 2009, the Company recorded a current and non-current receivable related to the Cash Flow Swap. As such, all or a portion of the receivable could be “at-risk” should the counterparty fail to perform. The Company has provided a letter of credit totaling $150,000,000, issued in support of the Cash Flow Swap.

Interest Rate Swap

At March 31, 2009, CRLLC held derivative contracts known as Interest Rate Swap agreements (the “Interest Rate Swap”) that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180,000,000. Half of the Interest Rate Swap agreements are held with a related party (as described in Note 14, “Related Party Transactions”), and the other half are held with a financial institution that is a lender under CRLLC’s long-term debt agreement. The Interest Rate Swap agreements carry the following terms:


	Notional		Fixed
Period Covered	Amount		Interest Rate

March 31, 2009 to March 30, 2010	$	180 million		4.195	%
March 31, 2010 to June 30, 2010		110 million		4.195	%

CVR pays the fixed rates listed above and receives a floating rate based on three month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The Interest Rate Swap results in both realized and unrealized gains or losses and is included in the Company’s Consolidated Statements of Operations. The realized gain or loss from the Interest Rate Swap is settled quarterly. The Interest Rate Swap is marked to market each reporting date. Transactions related to the interest rate swap agreements are not allocated to the Petroleum or Nitrogen Fertilizer segments.

The Interest Rate Swap has two counterparties. As noted above, one half of the Interest Rate Swap agreements are held with a related party. As of March 31, 2009, both counterparties had an investment-grade debt rating. The maximum amount of loss due to the credit risk of the counterparty, should the counterparty fail to perform according to the terms of the contracts, is contingent upon the unsettled portion of the hedge, if any. For the Company to be “at-risk” the unsettled portion of the hedge would need to be in a net receivable position. As of March 31, 2009, the Company’s Interest Rate Swap was in a payable position and thus would not be considered “at-risk” as it relates to risk posed by the swap counterparties.


(14)	Related Party Transactions

The Goldman Sachs Funds, or GS, and the Kelso Funds, or Kelso together own a majority of the common stock of the Company.

Cash Flow Swap

CRLLC entered into certain crude oil, heating oil and gasoline swap agreements (referred to above and herein as the Cash Flow Swap) with J. Aron & Company (“J. Aron”), a subsidiary of GS. These agreements were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in Note 13,

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

“Derivative Financial Instruments”). Realized and unrealized losses totaling $35,828,000 and $35,423,000 were recognized related to these swap agreements for the three months ended March 31, 2009 and 2008, respectively, and are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at March 31, 2009, includes an asset of $18,355,000 included in current receivable from swap counterparty and $2,433,000 included in long-term receivable from swap counterparty. Also reflected in the Consolidated Balance Sheet at March 31, 2009 is a payable to swap counterparty for $15,714,000. This amount represents the realized loss on the Cash Flow Swap for the three months ended March 31, 2009. As of December 31, 2008, the Company recorded short-term and long-term receivable from swap counterparty of $32,630,000 and $5,632,000, respectively, for the unrealized gain on the Cash Flow Swap as of December 31, 2008.

J. Aron Deferrals

As a result of the June/July 2007 flood and the related temporary cessation of business operations, the Company entered into deferral agreements for amounts owed to J. Aron under the Cash Flow Swap discussed above. The amount deferred, excluding accrued interest, totaled $123,681,000. Of the deferred balances, $61,306,000 had been repaid as of December 31, 2008. The remaining deferred liability is included in the Consolidated Balance Sheet at December 31, 2008 in payable to swap counterparty, as it was ultimately deferred to July 2009. Accrued interest related to the deferral agreement for the year ended December 31, 2008 totaled $202,000 and is included in other current liabilities. Interest expense related to the deferral agreement totaled $307,000 and $1,249,000 for the three months ended March 31, 2009 and 2008, respectively.

In the first quarter of 2009, the Company repaid the entire remaining deferral obligation of $62,375,000, including accrued interest of $509,000, resulting in the Company being released from any and all of its obligations under the deferral agreements.

Interest Rate Swap

On June 30, 2005, the Company also entered into three Interest Rate Swap agreements (referred to above as the Interest Rate Swap) with J. Aron (as described in Note 13, “Derivative Financial Instruments”). Losses totaling $97,000 and $2,813,000 were recognized related to these swap agreements for the three months ended March 31, 2009 and 2008, respectively, and are reflected in gain (loss) on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheets at March 31, 2009 and December 31, 2008 includes $2,508,000 and $2,595,000, respectively, in other current liabilities and $627,000 and $1,298,000, respectively, in other long-term liabilities related to the same agreements.

Crude Oil Supply Agreement

During 2008, the Company was a counterparty to a crude oil supply agreement with J. Aron. Under the agreement, the parties agreed to negotiate the cost of each barrel of crude oil to be purchased from a third party, and CRRM agreed to pay J. Aron a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost was adjusted further using a spread adjustment calculation based on the time period the crude oil was estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The Company recorded $0 and $8,211,000 on the Consolidated Balance Sheets at March 31, 2009 and December 31, 2008, respectively, in prepaid expenses and other current assets for the prepayment of crude oil. In addition, $0 and $20,063,000 were recorded in inventory and $0 and $2,757,000 were recorded in accounts payable at March 31, 2009 and December 31, 2008, respectively. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the three months ended March 31, 2009 and 2008 totaled $0 and $766,213,000, respectively. The crude oil supply agreement was terminated with J. Aron effective December 31, 2008. The Company entered

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

into a new crude oil supply agreement with Vitol Inc., an unrelated party, effective December 31, 2008, with a termination date two years from the effective date.

Cash and Cash Equivalents

The Company opened a highly liquid money market account with average maturities of less than 90 days within the Goldman Sachs fund family in September 2008. As of March 31, 2009 and December 31, 2008, the balance in the account was approximately $17,664,000 and $149,000, respectively. For the three months ended March 31, 2009, the account earned interest income of $16,000.

Other

For the three months ended March 31, 2009, the Company purchased approximately $77,000 of Fluid Catalytic Cracking Unit additives from Intercat, Inc. A director of the Company, Mr. Regis Lippert, is also the Director, President, CEO and majority shareholder of Intercat, Inc.

(15) Business Segments

CVR measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. All operations of the segments are located within the United States.

Petroleum

Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products including pet coke. CVR sells the pet coke to the Partnership for use in the manufacturing of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For CVR, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by the fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were $3,018,000 and $2,806,000 for the three months ended March 31, 2009 and 2008, respectively.

Intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “Nitrogen Fertilizer” was $658,000 and $5,291,000 for the three months ended March 31, 2009 and 2008, respectively.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $3,536,000 and $2,545,000 for the three months ended March 31, 2009 and 2008, respectively.

Sales of hydrogen to the Petroleum Segment have been reflected as net sales for the Nitrogen Fertilizer Segment. For the three months ended March 31, 2009 and 2008, the net sales generated from intercompany hydrogen sales were $658,000 and $5,291,000, respectively. These intercompany transactions are eliminated in the Other Segment.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Segment

The Other Segment reflects intercompany eliminations, including significant intercompany eliminations of receivables and payables between the segments, cash and cash equivalents, all debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments.


	Three Months Ended
	March 31,
	2009			2008
	(in thousands)

Net sales
Petroleum	$	545,282		$	1,168,500
Nitrogen Fertilizer		67,789			62,600
Intersegment eliminations		(3,676	)		(8,097	)

Total	$	609,395		$	1,223,003

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	417,598		$	1,035,085
Nitrogen Fertilizer		8,682			8,945
Intersegment eliminations		(4,675	)		(7,836	)

Total	$	421,605		$	1,036,194

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	34,622		$	40,290
Nitrogen Fertilizer		21,612			20,266
Other		—			—

Total	$	56,234		$	60,556

Net costs associated with flood
Petroleum	$	181		$	5,533
Nitrogen Fertilizer		—			(17	)
Other		—			247

Total		181		$	5,763

Depreciation and amortization
Petroleum	$	15,878		$	14,877
Nitrogen Fertilizer		4,616			4,477
Other		415			281

Total	$	20,909		$	19,635

Operating income
Petroleum	$	64,659		$	63,618
Nitrogen Fertilizer		29,282			26,017
Other		(2,981	)		(2,277	)

Total	$	90,960		$	87,358

Capital expenditures
Petroleum	$	7,392		$	22,541
Nitrogen Fertilizer		7,431			2,817
Other		1,095			798

Total	$	15,918		$	26,156


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes and with the statistical information and financial data appearing in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 as well as our Annual Report on Form 10-K for the year ended December 31, 2008. Results of operations for the three months ended March 31, 2009 are not necessarily indicative of results to be attained for any other period.

Forward-Looking Statements

This Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains “forward-looking statements” as defined by the Securities and Exchange Commission (the “SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:


	•	statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

	•	statements relating to future financial performance, future capital sources and other matters; and

	•	any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008. Such factors include, among others:


	•	volatile petroleum products resulting in volatile refining margins;

	•	exposure to the risks associated with volatile crude prices;

	•	the availability of adequate cash and other sources of liquidity for our capital needs;

	•	disruption of our ability to obtain an adequate supply of crude oil;

	•	losses due to the Cash Flow Swap;

	•	interruption of the pipelines supplying feedstock and in the distribution of our products;

	•	competition in the petroleum and nitrogen fertilizer businesses;

	•	continued significant declines in natural gas prices, which historically has correlated with the market price of nitrogen fertilizer products;

	•	the cyclical nature of the nitrogen fertilizer business;

	•	the dependence of the nitrogen fertilizer operations on a few third-party suppliers;

	•	the hazardous nature of ammonia, potential liability for accidents involving ammonia that cause severe damage to property and/or injury to the environment and human health and potential increased costs relating to transport of ammonia;


	•	the reliance of the nitrogen fertilizer business on third-party providers of transportation services and equipment;

	•	operating hazards and interruptions, including unscheduled downtime and maintenance;

	•	capital expenditures required by environmental laws and regulations for the petroleum and nitrogen fertilizer businesses;

	•	changes in our credit profile;

	•	our significant indebtedness

	•	severe weather conditions and natural disasters;

	•	the supply and price levels of essential raw materials; and

	•	the international credit crisis and global recession.

All forward-looking statements contained in this Form 10-Q speak only as of the date of this document. We undertake no obligation to update or revise publicly any forward-looking statements to reflect events or circumstances that occur after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.

Company Overview

CVR Energy, Inc. and, unless the context requires otherwise, its subsidiaries (“CVR”, the “Company”, “we”, “us” or “our”) is an independent refiner and marketer of high value transportation fuels. In addition, we currently own all of the interests (other than the managing general partner interest (“managing GP interest”) and associated incentive distribution rights (the “IDRs”) in CVR Partners, LP (the “Partnership”) a limited partnership which produces the nitrogen fertilizers, ammonia and urea ammonium nitrate (“UAN”).

Any references to the “Company” as of a date prior to October 16, 2007 and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries. CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”).

We operate under two business segments: petroleum and nitrogen fertilizer. Throughout the remainder of this document, our business segments are referred to as our “petroleum business” and our “nitrogen fertilizer business,” respectively.

Petroleum business. Our petroleum business includes a 115,000 barrels per day (“bpd”) complex full coking medium-sour crude refinery in Coffeyville, Kansas. In addition to the refinery, we own and operate supporting businesses that include (1) a crude oil gathering system serving central Kansas, northern Oklahoma, western Missouri, eastern Colorado and southwest Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels and (4) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and to customers at throughput terminals on Magellan Midstream Partners L.P.’s (“Magellan”) refined products distribution systems. Additionally, we lease 2.7 million barrels of storage capacity at Cushing, Oklahoma. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via the Magellan pipeline and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. and NuStar Energy, L.P. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline.

Crude oil is supplied to our refinery through our owned and leased gathering system and by a Plains American L.P. pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead Pipeline from Canada and receive foreign and deepwater domestic crude oils via the Seaway Pipeline system. We have also signed a contract for additional pipeline capacity on the proposed Keystone pipeline project currently under development. We also maintain leased storage in Cushing to facilitate optimal crude purchasing and blending. Our refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics and a variety of South American, North Sea, Middle East and West African imported grades. The access to a variety of crude oils coupled with the complexity of our refinery allows us to purchase crude oil at a discount to West Texas Intermediate, (“WTI”). Our crude consumed cost discount to WTI for the first quarter of 2009 was $(6.47) per barrel compared to $(5.31) per barrel in the first quarter of 2008.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility, comprised of (1) an 84 million standard cubic foot per day gasifier complex, which consumes approximately 1,500 tons per day of pet coke to produce hydrogen, (2) a 1,225 ton-per-day ammonia unit and (3) a 2,025 ton-per-day UAN unit. In 2008, the nitrogen fertilizer business produced approximately 359,120 tons of ammonia, of which approximately 69% was upgraded into approximately 599,172 tons of UAN.

The nitrogen fertilizer plant in Coffeyville, Kansas includes a pet coke gasifier that produces high purity hydrogen which in turn is converted to ammonia at a related ammonia synthesis plant. Ammonia is further upgraded into UAN solution in a related UAN unit. Pet coke is a low value by-product of the refinery coking process. On average during the last five years, more than 77% of the pet coke consumed by the nitrogen fertilizer plant was produced by our refinery. The nitrogen fertilizer business obtains most of its pet coke via a long-term coke supply agreement with our refinery.

The nitrogen fertilizer plant is the only operation in North America utilizing a pet coke gasification process to produce nitrogen fertilizers (based on data provided by Blue Johnson & Associates). Its redundant train gasifier provides good on-stream reliability and the use of low cost by-product pet coke feed (rather than natural gas) to produce hydrogen provides the facility with a significant competitive advantage during periods of high natural gas prices. Fertilizer prices generally increase with natural gas prices, without a directly related change in cost (because pet coke is used as a primary raw material rather than natural gas). The nitrogen fertilizer business’ competition utilizes natural gas to produce ammonia.

With the recent downturn in the economy, natural gas consumption has declined, resulting in a significant decrease in natural gas prices in recent months. Prices dipped below $4 per MMBtu as of March 31, 2009. The recent decline in natural gas prices has enabled natural gas based producers to manufacture at lower costs; which may impact prices of nitrogen fertilizer.

General Overview. Due to the weakness of the general economy, including the tightness in the credit markets, and short-term tightening in demand of the petroleum and nitrogen fertilizer products, both the petroleum business and nitrogen fertilizer business are focused on enhancing operational efficiency, controlling operational expenditures and minimizing capital spending. Inventory management practices are being employed to respond to the changes in demand levels which impact our production volumes in both businesses.

Major Influences on Results of Operations

Petroleum Business.

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of, and demand for, crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions,

domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out, or FIFO, accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, domestic and international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast.

In order to assess our operating performance, we compare our net sales, less cost of product sold, or our refining margin, against a widely used industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil is converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect our refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude differential. Our refinery margin can be impacted significantly by the consumed crude differential. Our consumed crude differential will move directionally with changes in the West Texas Sour crude oil (“WTS”) differential to WTI and the West Canadian Select (“WCS”) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude differential and published differentials will vary depending on the volume of medium sour crude and heavy sour crude we purchase as a percent of our total crude volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate. The WTI less WCS differential was $3.26 and $19.84 per barrel, for the three months ended March 31, 2009 and 2008, respectively. The WTI less WTS differential was $1.04 and $4.63 per barrel for the three months ended March 31, 2009 and 2008, respectively. While there was contraction in the sweet-sour and heavy-sour crude oil markets during the first quarter of 2009, the impact of this contraction on our crude differential was offset in part due to the ongoing contango in the WTI crude oil market. Contango markets are characterized by prices for future delivery that are higher than the current or spot price of the commodity. Our quarterly crude costs benefited in the first quarter of 2009 from the ongoing contango. Our consumed crude less WTI differential was $(6.47) and $(5.31) per barrel for the three months ended March 31, 2009 and 2008, respectively.

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX are different from the actual production in our refinery, is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and heating oil

PADD II, Group 3 vs. NYMEX basis, or heating oil basis. If gasoline and heating oil basis are greater than zero, this would mean that prices in our marketing area exceed those used in the 2-1-1 crack spread. Heating oil basis for the first quarter 2009 and 2008 was $(1.82) and $3.65 per barrel, respectively. Gasoline basis for the first quarter 2009 was $(0.64) per barrel, compared to $(1.46) per barrel in the first quarter of 2008.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices.

Consistent, safe, and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense, a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refinery generally undergoes a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The last refinery turnaround was completed in April 2007, and the next refinery turnaround is scheduled for the fourth quarter of 2011.

Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower target inventory we are able to maintain significantly reduces the impact of commodity price volatility on our petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Our hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results unless the market value of our target inventory is increased above cost.

As the petroleum business has continued to increase its product output and, for the first quarter 2009, has experienced record levels of outbound shipments, product shipping logistics are beginning to surface as a potential limitation. We are continuing to evaluate and look at alternatives for shipping refined products out of the refinery. We do not expect any outbound transportation constraints to have a material or significant impact to the results of the operations of the petroleum business.

Nitrogen Fertilizer Business.

In the nitrogen fertilizer business, earnings and cash flow from operations are primarily affected by the relationship between nitrogen fertilizer product prices and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business uses minimal natural gas and, as a result, is not directly impacted in terms of cost, by high or volatile swings in natural gas prices. Instead, our adjacent oil refinery supplies most of the pet coke feedstock needed by the nitrogen fertilizer business pursuant to a long-term coke supply agreement we entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the supply of, and the demand for, nitrogen fertilizer products which, in turn, depends on, among other factors, the price of natural gas, the cost and availability of fertilizer transportation infrastructure, changes in the world population, weather conditions, grain production levels, the availability of imports, and the extent of government intervention in agriculture markets. While net sales of the nitrogen fertilizer business could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and nitrogen fertilizer products sell at low prices, high natural gas prices do not force the nitrogen fertilizer business to shut down its operations as is the case with our competitors who rely heavily on natural gas instead of pet coke as a primary feedstock.

Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. Natural gas costs and the price of nitrogen fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade of competitors’ facilities, price

volatility, domestic and international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

The demand for nitrogen fertilizers is affected by the aggregate crop planting decisions and nitrogen fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of nitrogen fertilizer they apply depend on factors such as crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

The United States Department of Agriculture reported on March 31, 2009 that growers plan to plant 85 million acres of corn in 2009. While this number is down from the prior two periods, it is the third largest acreage since 1949. Due to the growing global population, expectations remain for future increased demand in spite of the global economic downturn.

The nitrogen fertilizer spring application period was negatively impacted by the limited planting caused by late winter storms and recent persistent wet weather in the mid-continent. This delay will result in a shortened but potentially more intense application period as weather permits.

We anticipate that second quarter plant gate prices will continue to be above current prices due to the impact of our order book. Over time, prices should trend downward toward spot prices; however, at this time with the current delay of the planting season, we cannot estimate the full impact.

In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. Instead of experiencing high variability in the cost of raw materials, the nitrogen fertilizer business utilizes less than 1% of the natural gas used by natural gas-based fertilizer producers.

Because the nitrogen fertilizer plant has certain logistical advantages relative to end users of ammonia and UAN and demand relative to our production has remained high, the nitrogen fertilizer business primarily targets end users in the U.S. farm belt where it incurs lower freight costs as compared to competitors. The nitrogen fertilizer business does not incur any barge or pipeline freight charges when it sells in these markets, giving us a distribution cost advantage over U.S. Gulf Coast importers. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2008, the nitrogen fertilizer business upgraded approximately 69% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

The direct operating expense structure of the nitrogen fertilizer business also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has significantly higher fixed costs than natural gas-based fertilizer plants. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These costs comprise the fixed costs associated with the nitrogen fertilizer plant.

The nitrogen fertilizer business’ largest raw material expense is pet coke, which it purchases from our refinery and third parties. In 2008, the nitrogen fertilizer business spent $14.1 million for pet coke. If pet coke prices rise substantially in the future, the nitrogen fertilizer business may be unable to increase its prices to recover increased raw material costs, because market prices for nitrogen fertilizer products are generally correlated with natural gas prices, the primary raw material used by its competitors, and not pet coke prices.

Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost

margin opportunity, increased maintenance expense, a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors.

The nitrogen fertilizer business generally undergoes a facility turnaround every two years. The turnaround typically lasts 15-20 days each turnaround year and costs approximately $3-5 million per turnaround. The facility underwent a turnaround in the fourth quarter of 2008, and the next facility turnaround is currently scheduled for the fourth quarter of 2010.

Factors Affecting Comparability of Our Financial Results

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Cash Flow Swap

On June 16, 2005, CALLC entered into commodity derivative contracts (referred to as the “Cash Flow Swap”) with J. Aron & Company (“J. Aron”), a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. The Cash Flow Swap was subsequently assigned from CALLC to Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 57% and 14% of crude oil capacity for the periods January 1, 2009 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, the Statement of Operations reflects all the realized and unrealized gains and losses from this swap which can create significant changes between periods.

For the three months ended March 31, 2009 and 2008, we recorded net realized losses of $15.7 million and $21.5 million, respectively, related to the Cash Flow Swap. For the three months ended March 31, 2009 and 2008, we recorded net unrealized losses of $20.1 million and $13.9 million, respectively, related to the Cash Flow Swap.

Share-Based Compensation

Through a wholly-owned subsidiary, we have two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. We account for awards under our Phantom Unit Plans as liability based awards. In accordance with FAS 123(R), the expense associated with these awards for 2009 is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of our common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.

Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting guidance in EITF Issue No. 00-12, Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee and EITF Issue No. 96-18, Accounting for Equity Investments that Are Issued to Other than Employees for Acquiring or in Conjunction with Selling Goods or Services. In accordance with that

accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. For the three months ended March 31, 2009 and 2008, we increased (reversed) compensation expense by $3.8 million and $(0.5) million, respectively, as a result of the phantom and override unit share-based compensation awards.

Results of Operations

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three months ended March 31, 2009 and 2008. The summary financial data for our two operating segments does not include certain selling, general and administrative expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” except for the balance sheet data as of December 31, 2008, is unaudited.


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)
	(in millions, except share data)

Consolidated Statement of Operations Data
Net sales	$	609.4		$	1,223.0
Cost of product sold(1)		421.6			1,036.2
Direct operating expenses(1)		56.2			60.6
Selling, general and administrative expenses(1)		19.5			13.4
Net costs associated with flood(2)		0.2			5.8
Depreciation and amortization(3)		20.9			19.6

Operating income	$	91.0		$	87.4
Other income, net		0.1			0.9
Interest expense and other financing costs		(11.5	)		(11.3	)
Gain (loss) on derivatives, net		(36.9	)		(47.9	)

Income before income tax expense	$	42.7		$	29.1
Income tax expense		12.0			6.9

Net income(4)	$	30.7		$	22.2
Basic earnings per share	$	0.36		$	0.26
Diluted earnings per share	$	0.36		$	0.26
Weighted average common shares outstanding:
Basic		86,243,745			86,141,291
Diluted		86,322,411			86,158,791


	As of March 31,		As of December 31,
	2009		2008
	(unaudited)
	(in millions)

Balance Sheet Data
Cash and cash equivalents	$	28.4	$	8.9
Working capital		174.9		128.5
Total assets		1,575.8		1,610.5
Total debt, including current portion		490.9		495.9
Total CVR stockholders’ equity		612.1		579.5


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)
	(in millions)

Cash Flow Data
Net cash flow provided by (used in):
Operating activities		36.7			24.2
Investing activities		(15.9	)		(26.2	)
Financing activities		(1.3	)		(3.4	)
Other Financial Data
Capital expenditures for property, plant and equipment	$	15.9		$	26.2
Depreciation and amortization		20.9			19.6
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(5)		42.8			30.6


(1)		Amounts are shown exclusive of depreciation and amortization.

(2)		Represents the approximate net costs associated with the June/July 2007 flood and crude oil spill that are not probable of recovery.

(3)		Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general administrative expenses:


	Three Months Ended
	March 31,
	2009		2008
	(unaudited)
	(in millions)

Depreciation and amortization excluded from cost of product sold	$	0.7	$	0.6
Depreciation and amortization excluded from direct operating expenses		19.7		18.7
Depreciation and amortization excluded from selling, general and administrative expenses		0.5		0.3

Total depreciation and amortization	$	20.9	$	19.6


(4)		The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance:


	Three Months Ended
	March 31,
	2009		2008
	(unaudited)
	(in millions)

Funded letter of credit expense and interest rate swap not included in interest expense(a)	$	4.3	$	0.9
Unrealized net (gain) loss from Cash Flow Swap		20.1		13.9
Share-based compensation expense(b)		3.9		(0.4	)


(a)		Consists of fees which are expensed to selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of consolidated adjusted EBITDA in the credit facility.

(b)		Represents the impact of share-based compensation awards.


(5)		Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the acquisition of Coffeyville Group Holdings,


		LLC by CALLC on June 24, 2005. On June 16, 2005, CALLC entered into the Cash Flow Swap with J. Aron. The Cash Flow Swap was subsequently assigned from CALLC to CRLLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 57% and 14% of crude oil capacity for the periods January 1, 2009 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively.

		We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic Statements of Operations reflect in each period material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which are accounted for as an asset or liability on our balance sheet, as applicable. As the absolute crack spreads increase, we are required to record an increase in this liability account with a corresponding expense entry to be made to our Statements of Operations. Conversely, as absolute crack spreads decline, we are required to record a decrease in the swap related liability and post a corresponding income entry to our Statement of Operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrealized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business and assessing its growth and profitability from a strategic and financial planning perspective, management and our board of directors considers our GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark-to-market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized gain or loss from Cash Flow Swap net of its related tax effect.

		Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized financial measure under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of financial performance or liquidity in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark-to-market adjustments, the measure does not reflect the fair market value of our Cash Flow Swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.

The following is a reconciliation of Net income adjusted for unrealized gain or loss from Cash Flow Swap to net income (in millions):


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)

Net income adjusted for unrealized gain or loss from Cash Flow Swap	$	42.8		$	30.6
Plus:
Unrealized gain (loss) from Cash Flow Swap, net of taxes		(12.1	)		(8.4	)

Net income	$	30.7		$	22.2

Petroleum Business Results of Operations

The following tables below provide an overview of the petroleum business’ results of operations, relevant market indicators and its key operating statistics:


	Three Months Ended
	March 31,
	2009		2008
	(unaudited)
	(in millions, except operating statistics)

Petroleum Business Financial Results
Net sales	$	545.3	$	1,168.5
Cost of product sold(1)		417.6		1,035.1
Direct operating expenses(1)(3)		34.6		40.3
Net costs associated with flood		0.2		5.5
Depreciation and amortization		15.9		14.9

Gross profit(3)	$	77.0	$	72.7
Plus direct operating expenses(1)		34.6		40.3
Plus net costs associated with flood		0.2		5.5
Plus depreciation and amortization		15.9		14.9

Refining margin(2)		127.7		133.4
Operating income		64.7		63.6
Key Operating Statistics (per crude oil throughput barrel)
Refining margin(2)(3)	$	13.36	$	13.77
Gross profit(3)	$	8.06	$	7.51
Direct operating expenses(1)(3)	$	3.62	$	4.16


	Three Months Ended March 31,
	2009				2008
			%				%

Refining Throughput and Production Data (bpd)
Throughput:
Sweet		74,958		62.1		73,043		61.0
Light/medium sour		20,733		17.2		18,079		15.1
Heavy sour		10,478		8.7		15,323		12.8

Total crude oil throughput		106,169		88.0		106,445		88.9
All other feedstocks and blendstocks		14,498		12.0		13,282		11.1

Total throughput		120,667		100.0		119,727		100.0

Production:
Gasoline		64,327		53.3		59,662		49.4
Distillate		46,184		38.3		48,591		40.3
Other (excluding internally produced fuel)		10,133		8.4		12,467		10.3

Total refining production (excluding internally produced fuel)		120,644		100.0		120,720		100.0
Product price (dollars per gallon):
Gasoline			$	1.24			$	2.45
Distillate			$	1.32			$	2.85


	Three Months Ended
	March 31,
	2009			2008

Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	43.31		$	97.82
Crude Oil Differentials:
WTI less WTS (light/medium sour)		1.04			4.63
WTI less WCS (heavy sour)		3.26			19.84
NYMEX Crack Spreads:
Gasoline		9.07			6.46
Heating Oil		13.13			17.16
NYMEX 2-1-1 Crack Spread		11.10			11.81
PADD II Group 3 Basis:
Gasoline		(0.64	)		(1.46	)
Ultra Low Sulfur Diesel		(1.82	)		3.65
PADD II Group 3 Product Crack:
Gasoline		8.43			5.00
Ultra Low Sulfur Diesel		11.31			20.81
PADD II Group 3 2-1-1		9.87			12.90


(1)		Amounts are shown exclusive of depreciation and amortization.

(2)		Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) is taken directly from our Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period.

(3)		In order to derive the refining margin, direct operating expense and gross profit in each case per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period.

Nitrogen Fertilizer Business Results of Operations

The tables below provide an overview of the nitrogen fertilizer business’ results of operations, relevant market indicators and key operating statistics:


	Three Months Ended
	March 31,
	2009		2008
	(unaudited)
	(in millions)

Nitrogen Fertilizer Business Financial Results
Net sales	$	67.8	$	62.6
Cost of product sold(1)		8.7		8.9
Direct operating expenses(1)		21.6		20.3
Depreciation and amortization		4.6		4.5
Operating income	$	29.3	$	26.0


	Three Months Ended
	March 31,
	2009			2008
	(unaudited)

Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(2)		108.0			83.7
Ammonia (net available for sale)(2)		38.8			22.1
UAN		169.7			150.1
Petroleum coke consumed (thousand tons)		125.3			118.1
Petroleum coke (cost per ton)	$	35		$	30
Sales (thousand tons)(3):
Ammonia		48.0			24.1
UAN		143.0			158.0

Total sales		191.0			182.1
Product pricing (plant gate) (dollars per ton)(3):
Ammonia	$	373		$	494
UAN	$	316		$	262
On-stream factor(4):
Gasification		100.0	%		91.8	%
Ammonia		100.0	%		90.7	%
UAN		96.0	%		85.9	%
Reconciliation to net sales (dollars in thousands):
Freight in revenue	$	4,121		$	4,022
Hydrogen revenue		658			5,291
Sales net plant gate		63,010			53,287

Total net sales	$	67,789		$	62,600


	Three Months Ended
	March 31,
	2009		2008
	(unaudited)

Market Indicators
Natural gas NYMEX (dollars per MMBtu)	$	4.47	$	8.74
Ammonia — Southern Plains (dollars per ton)	$	337	$	590
UAN — Mid Cornbelt (dollars per ton)	$	274	$	371


(1)		Amounts are shown exclusive of depreciation and amortization.

(2)		The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN.

(3)		Plant gate sales per ton represent net sales less freight and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.

(4)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.

Three Months Ended March 31, 2009 Compared to the Three Months Ended March 31, 2008

Consolidated Results of Operations

Net Sales. Consolidated net sales were $609.4 million for the three months ended March 31, 2009 compared to $1,223.0 million for the three months ended March 31, 2008. The decrease of $613.6 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily due to a decrease in petroleum net sales of $623.2 million that resulted from lower product prices ($598.2 million) and lower sales volumes ($25.0 million). Nitrogen fertilizer net sales increased $5.2 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 primarily due to higher plant gate prices ($3.0 million) and higher overall sales volume ($2.2 million).

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $421.6 million for the three months ended March 31, 2009 as compared to $1,036.2 million for the three months ended March 31, 2008. The decrease of $614.6 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 primarily resulted from a significant decrease in raw material cost, primarily crude oil.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $56.2 million for the three months ended March 31, 2009 as compared to $60.6 million for the three months ended March 31, 2008. This decrease of $4.4 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was due to a decrease in petroleum direct operating expenses of $5.7 million, primarily related to decreases in expenses associated with utilities and energy, repairs and maintenance, property taxes, outside services, operating materials and environmental, partially offset by increases in expenses associated with labor, insurance, rent and chemicals. Nitrogen fertilizer direct operating expenses increased during the comparable period by $1.3 million, primarily due to increases in expenses associated with utilities, labor, property taxes, catalyst and outside services, partially offset by decreases in expenses associated with repairs and maintenance.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $19.5 million for the three months ended March 31, 2009 as compared to $13.4 million for the three months ended March 31, 2008. This variance was primarily the result of a decrease in expenses associated with outside

services ($0.8 million) which was more than offset by increases in expenses related to share-based compensation ($3.5 million), administrative payroll ($1.8 million), and bank charges ($1.2 million).

Net Costs Associated with Flood. Consolidated net costs associated with flood for the three months ended March 31, 2009 approximated $0.2 million as compared to $5.8 million for the three months ended March 31, 2008.

Depreciation and Amortization. Consolidated depreciation and amortization was $20.9 million for the three months ended March 31, 2009 as compared to $19.6 million for the three months ended March 31, 2008. The increase in depreciation and amortization for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was the result of additional capital projects completed throughout 2008.

Operating Income. Consolidated operating income was $91.0 million for the three months ended March 31, 2009 as compared to an operating income of $87.4 million for the three months ended March 31, 2008. For the three months ended March 31, 2009 as compared to the three months ended March 31, 2008, petroleum operating income increased $1.1 million and nitrogen fertilizer operating income increased by $3.4 million.

Interest Expense. Consolidated interest expense for the three months ended March 31, 2009 was $11.5 million as compared to interest expense of $11.3 million for the three months ended March 31, 2008. This 0.2 million increase for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 primarily resulted from an overall increase in the borrowing rates as a result of the second amendment to our credit facility completed on December 22, 2008. This amendment resulted in an increase of interest rate margin, and LIBOR and the base rate have been set at a minimum of 3.25% and 4.25%, respectively. The increase in interest expense as a result of the amendments impact on interest rate margin and base rates was partially offset by a decrease in average borrowings outstanding during the comparable periods.

Interest Income. Interest income was nominal for the three months ended March 31, 2009 as compared to $0.7 million for the three months ended March 31, 2008.

Gain (loss) on Derivatives, net. We have determined that the Cash Flow Swap and our other derivative instruments do not qualify as hedges for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. For the three months ended March 31, 2009, we incurred $36.9 million in losses on derivatives. This compares to a $47.9 million net loss on derivatives for the three months ended March 31, 2008. This decrease in loss on derivatives, net for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily attributable to a decrease in realized and unrealized losses on hedge derivatives, excluding the Cash Flow Swap, of $11.4 million over the comparable period. With respect to the Cash Flow Swap, realized losses for the three months ended March 31, 2009 and the three months ended March 31, 2008 were $15.7 million and $21.5 million, respectively. The decrease in realized losses over the comparable periods was primarily the result of lower average crack spreads for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008. Unrealized losses represent the change in the mark-to-market value on the unrealized portion of the Cash Flow Swap based on changes in the NYMEX crack spread that is the basis for the Cash Flow Swap. Unrealized losses on our Cash Flow Swap for the three months ended March 31, 2009 and the three months ended March 31, 2008 were $20.1 million and $13.9 million, respectively.

Provision for Income Taxes. Income tax expense for the three months ended March 31, 2009 was $12.0 million, or 28.1% of income before income taxes, as compared to income tax expense of $6.9 million, or 23.6% of earnings before income taxes, for the three months ended March 31, 2008. This increase in the effective income tax rate is primarily related to a reduction of expected credits generated as a result of the production of ultra low sulfur diesel fuel and Kansas State incentives generated under the High Performance Incentive Program.

Net Income. For the three months ended March 31, 2009, net income increased to $30.7 million as compared to net income of $22.2 million for the three months ended March 31, 2008. Net income increased $8.5 million compared to the first quarter of 2008 primarily due to improved results in our petroleum and nitrogen fertilizer businesses, a reduction in losses on derivatives and a reduction of the net costs associated

with flood. These impacts were partially offset by increased selling, general and administrative expenses and a higher effective income tax rate.

Petroleum Business Results of Operations

Net Sales. Petroleum net sales were $545.3 million for the three months ended March 31, 2009 compared to $1,168.5 million for the three months ended March 31, 2008. The decrease of $623.2 million during the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of significantly lower product prices ($598.2 million) and lower overall sales volumes ($25.0 million). Our average sales price per gallon for the three months ended March 31, 2009 for gasoline of $1.24 and distillate of $1.32 decreased by 49% and 54%, respectively, as compared to the three months ended March 31, 2008.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold exclusive of depreciation and amortization was $417.6 million for the three months ended March 31, 2009 compared to $1,035.1 million for the three months ended March 31, 2008. The decrease of $617.5 million during the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of a significant decrease in crude oil prices and the impact of FIFO accounting also impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil consumed for the three months ended March 31, 2009 was $36.75 compared to $92.35 for the comparable period of 2008, a decrease of 60%. Sales volume of refined fuels decreased 4% for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the three months ended March 31, 2009, we had an unfavorable FIFO inventory impact of $6.0 million compared to a favorable FIFO inventory impact of $20.0 million for the comparable period of 2008.

Refining margin per barrel of crude throughput decreased from $13.77 for the three months ended March 31, 2008 to $13.36 for the three months ended March 31, 2009. Gross profit per barrel increased to $8.06 in the first quarter of 2009 as compared to gross profit per barrel of $7.51 in the equivalent period in 2008. The primary contributors to the slightly negative variance in refining margin per barrel of crude throughput were an increase in unfavorable FIFO impacts and decreases in crude oil differentials over the comparable periods. Decreased discounts for sour crude oils evidenced by the $1.04 per barrel, or 78%, decrease in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the WTS price, which is an indicator for the price of sour crude, negatively impacted refining margin for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008. In addition, a 6% decrease ($0.71 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods and negative regional differences between distillate prices in our primary marketing region (the Coffeyville supply area) and those of the NYMEX also negatively impacted refining margin per barrel over the comparable periods. The average distillate basis for the three months ended March 31, 2009 decreased by $5.47 per barrel to $(1.82) per barrel compared to $3.65 per barrel in the comparable period of 2008. Partially offsetting the negative effects of FIFO inventory losses, crude oil differentials, the NYMEX 2-1-1 crack spread and distillate basis was the steep crude oil discounts achieved during the three month period ended March 31, 2009 as a result of a steep contango in the U.S. crude oil market and improved basis between gasoline in the Coffeyville supply area and the NYMEX. The average gasoline basis increased by $0.82 per barrel to $(0.64) per barrel compared to $(1.46) per barrel in the comparable period of 2008.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses for our petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $34.6 million for the three months ended March 31, 2009 compared to direct operating expenses of $40.3 million for the three months ended March 31, 2008.

The decrease of $5.7 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008 was the result of decreases in expenses associated with utilities and energy ($3.0 million), repairs and maintenance ($2.5 million), property taxes ($1.2 million), outside services ($1.2 million), operating materials ($0.3 million) and environmental ($0.2 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with labor ($1.6 million), insurance ($0.7 million), rent ($0.2 million) and chemicals ($0.2 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude oil throughput for the three months ended March 31, 2009 decreased to $3.62 per barrel as compared to $4.16 per barrel for the three months ended March 31, 2008.

Net Costs Associated with Flood. Petroleum net costs associated with flood for the three months ended March 31, 2009 approximated $0.2 million compared to $5.5 million for the three months ended March 31, 2008.

Depreciation and Amortization. Petroleum depreciation and amortization was $15.9 million for the three months ended March 31, 2009 as compared to $14.9 million for the three months ended March 31, 2008. This increase in petroleum depreciation and amortization for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of the completion of several large capital projects in recent prior periods.

Operating Income. Petroleum operating income was $64.7 million for the three months ended March 31, 2009 as compared to $63.6 million for the three months ended March 31, 2008. This increase of $1.1 million from the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of improved gross profit per barrel and decreases in expenses associated with utilities and energy ($3.0 million), repairs and maintenance ($2.5 million), property taxes ($1.2 million), outside services ($1.2 million), operating materials ($0.3 million) and environmental ($0.2 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with labor ($1.6 million), insurance ($0.7 million), rent ($0.2 million) and chemicals ($0.2 million).

Nitrogen Fertilizer Business Results of Operations

Net Sales. Nitrogen fertilizer net sales were $67.8 million for the three months ended March 31, 2009 compared to $62.6 million for the three months ended March 31, 2008. The increase of $5.2 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was the result of both higher average plant gate prices ($3.0 million) and higher product sales volume ($2.2 million).

In regard to product sales volumes for the three months ended March 31, 2009, our nitrogen fertilizer operations experienced an increase of 99% in ammonia sales unit volumes and a decrease of 10% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification and the ammonia units increased over the comparable periods with both units reporting 100% on-stream for the three months ended March 31, 2009. The on-stream factor for the UAN plant was 96.0% for the three months ended March 31, 2009, which was also greater than the three months ended March 31, 2008. Although the on-stream factors for the three months ending March 31, 2009 were outstanding, it is typical to experience brief outages in complex manufacturing operations such as our nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.

Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both FOB our plant gate (sold plant) and FOB the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or three months to three months. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the three months ended March 31, 2009 for ammonia were lower than the comparable period of 2008 by 25%. Plant gate prices for the three months ended March 31, 2009 for UAN were greater than plant gate prices for the comparable period of 2008 by 21%.

The demand for nitrogen fertilizer is affected by the aggregate crop planting decisions and nitrogen fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of nitrogen fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold (excluding depreciation and amortization) for the three months ended March 31, 2009 was $8.7 million compared to $8.9 million for the three months ended March 31, 2008. The decrease of $0.2 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of an increase in expenses associated with petroleum coke ($0.9 million), more than offset by decreases in expenses associated with the change in inventory ($1.1 million) and distribution ($0.2 million).

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses for our nitrogen fertilizer operations include costs associated with the actual operations of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct operating expenses (exclusive of depreciation and amortization) for the three months ended March 31, 2009 were $21.6 million as compared to $20.3 million for the three months ended March 31, 2008. The increase of $1.3 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of increases in expenses associated with utilities ($1.9 million), labor ($0.5 million), taxes ($0.5 million), catalyst ($0.3 million) and outside services ($0.2 million). These increases in direct operating expenses were partially offset by decreases in expenses associated with repairs and maintenance ($2.5 million).

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased to $4.6 million for the three months ended March 31, 2009 as compared to $4.5 million for the three months ended March 31, 2008.

Operating Income. Nitrogen fertilizer operating income was $29.3 million for the three months ended March 31, 2009 as compared to operating income of $26.0 million for the three months ended March 31, 2008. This increase of $3.3 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was primarily the result of increased product sales volume and fertilizer prices over the comparable periods. Additionally, decreased direct operating expenses associated with repairs and maintenance ($2.5 million) also contributed to the positive operating income comparison over the comparable periods. These decreases in expenses were partially offset by increased direct operating expenses primarily the result of increases in expenses associated with utilities ($1.9 million), labor ($0.5 million), taxes ($0.5 million), catalyst ($0.3 million) and outside services ($0.2 million).

Liquidity and Capital Resources

Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash and cash equivalent balances and our existing revolving credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.

We believe that our cash flows from operations and existing cash and cash equivalent balances, together with borrowings under our existing revolving credit facility as necessary, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next 12 months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.

Cash Balance and Other Liquidity

As of March 31, 2009, we had cash and cash equivalents of $28.4 million. As of March 31, 2009 and April 30, 2009, we had no amounts outstanding under our revolving credit facility and aggregate availability of $116.1 million under our revolving credit facility. At April 30, 2009, we had cash and cash equivalents of $40.6 million.

At March 31, 2009, funded long-term debt, including current maturities, totaled $483.1 million of tranche D term loans. Other commitments at March 31, 2009 included a $150.0 million funded letter of credit facility and a $150.0 million revolving credit facility. As of December 31, 2008, the commitment outstanding on the revolving credit facility was $49.9 million, including $0 million in borrowings, $3.3 million in letters of credit in support of certain environmental obligations, and $46.6 million in letters of credit to secure transportation services for crude oil. As of April 30, 2009, total outstanding debt under our credit facility was $481.9 million, which was all term debt.

Working capital at March 31, 2009 was $174.9 million, consisting of $354.8 million in current assets and $179.9 million in current liabilities. Working capital at December 31, 2008 was $128.5 million, consisting of $373.4 million in current assets and $244.9 million in current liabilities.

Credit Facility

Our credit facility currently consists of tranche D term loans with an outstanding balance of $483.1 million at March 31, 2009, a $150.0 million revolving credit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap.

The $483.1 million of tranche D term loans outstanding as of March 31, 2009 are subject to quarterly principal amortization payments of 0.25% of the outstanding balance, increasing to 23.5% of the outstanding principal balance on April 1, 2013 and the next two quarters, with a final payment of the aggregate outstanding balance on December 28, 2013.

The revolving credit facility of $150.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving loan facility are subject to a $75.0 million sub-limit. Outstanding letters of credit reduce the amount available under our revolving credit facility. The revolving loan commitment expires on December 28, 2012. The borrower has an option to extend this maturity upon written notice to the lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is December 28, 2013. As of March 31, 2009, we had available $116.1 million under the revolving credit facility.

The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into a credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time upon written notice to the lenders. The funded letter of credit facility expires on December 28, 2010.

On December 22, 2008, CRLLC entered into a second amendment to its credit facility. The amendment was entered into, among other things, to amend the definition of consolidated adjusted EBITDA to add a FIFO adjustment which applies for the year ending December 31, 2008 through the quarter ending September 30, 2009. This FIFO adjustment will be used for the purpose of testing compliance with the financial covenants under the credit facility until the quarter ending June 30, 2010. CRLLC sought and obtained the amendment due to the dramatic decrease in the price of crude oil in the fourth quarter of 2008 and the effect that such crude oil price decrease would have had on the measurement of the financial ratios under the credit facility. As part of the amendment, CRLLC’s interest rate margin increased by 2.50%, and LIBOR and the base rate have been set at a minimum of 3.25% and 4.25%, respectively.

After giving effect to the second amendment, the credit facility incorporates the following pricing by facility type:


	•	Tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 4.50%, or, at the borrower’s option, (b) LIBOR plus 5.50% (with step-downs to the prime rate/federal funds rate plus 4.25% or 4.00% or LIBOR plus 5.25% or 5.50%, respectively, upon achievement of certain rating conditions).

	•	Revolving credit loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 4.50%, or, at the borrower’s option, (b) LIBOR plus 5.50% (with step-downs to the prime rate/federal funds rate plus 4.25% or 4.00% or LIBOR plus 5.25% or 5.00%, respectively, upon achievement of certain rating conditions). Revolving credit lenders receive commitment fees equal to the amount of undrawn revolving credit loans times 0.5% per annum.

	•	Letters of credit issued under the $75.0 million sub-limit available under the revolving credit facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving credit lenders and a fronting fee of 0.25% per annum owing to the issuing lender.

	•	Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. CRLLC is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit.

The amendment provides for more restrictive requirements. Among other things, CRLLC is subject to more stringent obligations under certain circumstances to make mandatory prepayments of loans. In addition, the amendment increased the percentage of excess cash flow during any fiscal year that must be used to prepay the loans and eliminated a “basket” which previously allowed CRLLC to pay dividends of up to $35.0 million per year.

The credit facility requires CRLLC to prepay outstanding loans, subject to certain exceptions. Some of the requirements, among other things, are as follows:


	•	100% of the asset sale proceeds must be used to repay outstanding loans;

	•	100% of the cash proceeds from the incurrence of specified debt obligations must be used to prepay outstanding loans; and

	•	100% of consolidated excess cash flow less 100% of voluntary prepayments made during the fiscal year must be used to prepay outstanding loans; provided that with respect to any fiscal year commencing with fiscal 2008, this percentage will be reduced to 75% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 or 50% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00.

Under the terms of our credit facility, the interest margin paid is subject to change based on changes in our leverage ratio and changes in our credit rating by either Standard & Poor’s (“S&P”) or Moody’s. S&P’s announcement in February 2009 to place the Company on negative outlook resulted in an increase in our interest rate of 0.25% on amounts borrowed under our term loan facility, revolving credit facility and the $150.0 million funded letter of credit facility.

The credit facility contains customary covenants, which, among other things, restrict, subject to certain exceptions, the ability of CRLLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The credit facility provides that CRLLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the estimated future production of refined products

based on the actual production for the three prior months) or for a term of longer than six years from December 28, 2006. In addition, CRLLC may not enter into material amendments related to any material rights under the Cash Flow Swap or the Partnership’s partnership agreement without the prior written approval of the requisite lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.

The credit facility also requires CRLLC to maintain certain financial ratios as follows:


	Minimum	Maximum
	Interest	Leverage
Fiscal Quarter Ending	Coverage Ratio	Ratio

March 31, 2009 — December 31, 2009	3.75:1.00	2.25:1.00
March 31, 2010 and thereafter	3.75:1.00	2.00:1.00

The computation of these ratios is governed by the specific terms of the credit facility and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA on a four quarter basis. In general, under the terms of our credit facility, consolidated adjusted EBITDA is calculated by adding on a consolidated basis, consolidated net income, consolidated interest expense, income tax expense, depreciation and amortization, other non- cash items, any fees and expenses related to permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests, major scheduled turnaround expenses and for purposes of computing the financial ratios (and compliance therewith), the FIFO adjustment, and then subtracting certain items that increase consolidated net income. As of March 31, 2009, we were in compliance with our covenants under the credit facility.

We present consolidated adjusted EBITDA because it is a material component of material covenants within our current credit facility and significantly impacts our liquidity and ability to borrow under our revolving line of credit. However, consolidated adjusted EBITDA is not a defined financial measure under GAAP and should not be considered as an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the credit facility as follows:


	For the Twelve Months
	Ended March 31,
	2009			2008
	(unaudited)
	(in millions)

Consolidated Financial Results
Net income	$	172.4		$	109.0
Plus:
Depreciation and amortization		83.4			73.8
Interest expense		40.5			60.6
Income tax expense		69.1			(34.4	)
Funded letters of credit expenses and interest rate swap not included in interest expense		10.8			2.7
Unrealized (gain) or loss on derivatives, net		(248.3	)		5.5
Non-cash compensation expense for equity awards		(15.4	)		25.2
(Gain) or loss on disposition of fixed assets		5.8			1.2
Unusual or nonrecurring charges		6.9			20.0
Property tax — increases due to abatement non-renewal		14.5			—
FIFO adjustment (unfavorable)(1)		136.7			—
Loss on extinguishment of debt		10.0			1.2
Minority interest in subsidiaries		—			0.5
Management fees		—			11.2
Major scheduled turnaround		3.3			10.4
Goodwill impairment		42.8			—

Consolidated adjusted EBITDA	$	332.5		$	286.9


(1)		The amendment to the credit facility entered into on December 22, 2008 amended the definition of consolidated adjusted EBITDA to add a FIFO adjustment. This amendment to the definition first applied for the year ending December 31, 2008 and will apply through the quarter ending September 30, 2009.

In addition to the financial covenants previously mentioned, the credit facility restricts the capital expenditures of CRLLC and its subsidiaries to $125 million in 2009, $80 million in 2010, and $50 million in 2011 and thereafter. The capital expenditures covenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year commencing with fiscal year 2009 if CRLLC obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ended December 31, 2008. We believe the limitations on our capital expenditures imposed by the credit facility should allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our credit facility.

The credit facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the credit facility, a breach of certain covenants under the credit facility, a breach of any representation or warranty contained in

the credit facility, any default under any of the documents entered into in connection with the credit facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20 million, events relating to employee benefit plans resulting in liability in excess of $20 million, a change in control, the guarantees, collateral documents or the credit facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the credit facility to have a lien on any material portion of the collateral, and any party under the credit facility (other than the agent or lenders under the credit facility) contesting the validity or enforceability of the credit facility.

The credit facility is subject to an intercreditor agreement among the lenders and the Cash Flow Swap provider, which deals with, among other things, priority of liens, payments and proceeds of sale of collateral.

Capital Spending

We divide our capital spending needs into two categories: non-discretionary, which is either capitalized or expensed, and discretionary, which is capitalized. Non-discretionary capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety regulations. Our non-discretionary capital expenditures for the 2009 first quarter were $6.0 million, of which approximately $5.5 million was spent in our petroleum business and $0.5 million in our nitrogen fertilizer business. We estimate that the total non-discretionary capital spending needs, including major scheduled turnaround expenses, of our refinery and the nitrogen fertilizer facilities will be approximately $58.4 million in the aggregate for 2009. This estimate includes, among other items, the capital costs necessary to comply with environmental regulations, including Tier II gasoline standards. As described above, our credit facilities limit the amount we can spend on capital expenditures.

We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. We have spent approximately $8.2 million of discretionary capital spend for the three months ended March 31, 2009.

Cash Flows

The following table sets forth our cash flows for the periods indicated below (in thousands):


	Three Months Ended
	March 31,
	2009			2008
	(Unaudited)

Net cash provided by (used in):
Operating activities	$	36,673		$	24,194
Investing activities		(15,918	)		(26,156	)
Financing activities		(1,251	)		(3,368	)

Net increase (decrease) in cash and cash equivalents	$	19,504		$	(5,330	)

Cash Flows Provided by Operating Activities

Net cash flows from operating activities for the three months ended March 31, 2009 was $36.7 million. The positive cash flow from operating activities generated over this period was primarily driven by $30.7 million of net income, favorable changes in other working capital, partially offset by unfavorable changes in trading working capital and other assets and liabilities over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is

defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net loss for the three months ended March 31, 2009 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2009 (approximately one year and three months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap decreased our net income over this period. Other sources of cash in other working capital included $34.6 million of restricted cash related to insurance proceeds, $24.8 million of accrued income taxes, $11.8 million of additional insurance proceeds partially offset by a $29.2 million use of cash related to the payable on the Cash Flow Swap. Trade working capital for the three months ended March 31, 2009 resulted in a use of cash of $82.5 million. For the three months ended March 31, 2009, accounts receivable increased $32.3 million, inventory increased by $24.7 million and accounts payable decreased by $29.1 million.

Net cash flows from operating activities for the three months ended March 31, 2008 was $24.2 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital and other assets and liabilities, partially offset by unfavorable changes in trading working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net loss for the three months ended March 31, 2008 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2008 (approximately two years and three months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $20.8 million increase in the payable to swap counterparty. Other sources of cash in other working capital included $16.6 million of deferred revenue related to prepaid fertilizer shipments and a $5.2 million increase in accrued income taxes. Trade working capital for the three months ended March 31, 2008 resulted in a use of cash of $67.5 million. For the three months ended March 31, 2008, accounts receivable increased $30.7 million, inventory increased by $31.6 million and accounts payable decreased by $5.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities for the three months ended March 31, 2009 was $15.9 million compared to $26.2 million for the three months ended March 31, 2008. The decrease in investing activities for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008 was the result of a decline in project related activity at our petroleum and nitrogen fertilizer operations.

Cash Flows Used in Financing Activities

Net cash used for financing activities for the three months ended March 31, 2009 was $1.3 million as compared to net cash used in financing activities of $3.4 million for the three months ended March 31, 2008. During the three months ended March 31, 2009, we paid $1.2 million of scheduled principal payments. During the three months ended March 31, 2008, we paid $1.2 million of scheduled principal payments and paid $2.1 million of initial public offering costs related to CVR Partners, LP.

Working Capital

Working capital at March 31, 2009, was $174.9 million, consisting of $354.8 million in current assets and $179.9 million in current liabilities. Working capital at December 31, 2008 was $128.5 million, consisting of

$373.4 million in current assets and $244.9 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of $116.1 million at March 31, 2009.

Letters of Credit

Our revolving credit facility provides for the issuance of letters of credit. At March 31, 2009, there were $33.9 million of irrevocable letters of credit outstanding, including $3.3 million in support of certain environmental obligators and $30.6 million to secure transportation services for crude oil.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2009.

Recent Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) Emerging Issues Task Force (“EITF”) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which became effective January 1, 2009 and is to be applied retrospectively. Under the FSP, unvested share-based payment awards which receive non-forfeitable dividend rights, or dividend equivalents are considered participating securities and are now required to be included in computing earnings per share under the two class method. As required we adopted this statement as of January 1, 2009. Based upon the nature of our share-based payment awards, it has been determined that these awards are not participating securities and therefore the FSP currently has no impact on our earnings per share calculations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedge items affect an entity’s financial position, net earnings, and cash flows. As required, the Company adopted this statement as of January 1, 2009. As a result of the adoption, we provided additional disclosures regarding its derivative instruments in notes to the condensed consolidated financial statements. There is no impact on our financial position or results of operation as a result of this adoption.

In February 2008, the FASB issued FASB Staff Position 157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). As required, we adopted SFAS 157 as of January 1, 2009. The adoption of SFAS 157 did not impact our financial position or earnings.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing noncontrolling interests. All other requirements of SFAS 160 must be applied prospectively. We adopted SFAS 160 effective January 1, 2009, and as a result have classified the noncontrolling interest (previously minority interest) as a separate component of equity for all periods presented.

Critical Accounting Policies

Our critical accounting policies are disclosed in the “Critical Accounting Policies” section of our Annual Report on Form 10-K for the year ended December 31, 2008. No modifications have been made to our critical accounting policies.


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. Information about market risks for the three months ended March 31, 2009 does not differ materially from that discussed under Part II — Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2008 . We are exposed to market pricing for all of the products sold in the future both at our petroleum business and the nitrogen fertilizer business, as all of the products manufactured in both businesses are commodities. As of March 31, 2009, all $483.1 million of outstanding debt under our credit facility was at floating rates; accordingly, an increase of 1.0% in our interest rate would result in an increase in our interest expense of approximately $4.8 million per year. None of our market risk sensitive instruments are held for trading.

Our earnings and cash flows and estimates of future cash flows are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depend on, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.


Item 4.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

Our management evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e) as of March 31, 2009. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, to ensure that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting required by Exchange Rule Act Rule 13a-15 that occurred during the fiscal quarter ended March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information


Item 1A.	*Risk Factors*

There are no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 under Part I — Item 1A. “Risk Factors.”


Item 6.	*Exhibits*


Number			Exhibit Title

	10	.6.1†*	First Amendment to Crude Oil Supply Agreement dated January 1, 2009 between Vitol, Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated herein by reference to Exhibit 10.6.1 to CVR Energy, Inc.’s Annual Report on Form 10-K, for the year ended December 31, 2008, filed on March 13, 2009.)
	10	.47*	Separation Agreement dated January 23, 2009 between James T. Rens, CVR Energy, Inc. and Coffeyville Resources, LLC (incorporated herein by reference to Exhibit 10.47 to CVR Energy, Inc.’s Annual Report on Form 10-K, for the year ended December 31, 2008, filed on March 13, 2009.)
	10	.48*	LLC Unit Agreement dated January 23, 2009 between Coffeyville Acquisition, LLC, Coffeyville Acquisition II, LLC, and Coffeyville Acquisition III, LLC and James T. Rens (incorporated herein by reference to Exhibit 10.48 to CVR Energy, Inc.’s Annual Report on Form 10-K, for the year ended December 31, 2008, filed on March 13, 2009.)
	31	.1	Certification of the Company’s Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.
	31	.2	Certification of the Company’s Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.
	32	.1	Certification of the Company’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Certification of the Company’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	*		Previously filed.
	†		Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has been granted by the SEC.


			Page No.

Part I. Financial Information
	Item 1.	Financial Statements		2
		Condensed Consolidated Balance Sheets — March 31, 2009 (unaudited) and December 31, 2008		2
		Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2009 and 2008 (unaudited)		3
		Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2009 and 2008 (unaudited)		4
		Notes to the Condensed Consolidated Financial Statements — March 31, 2009 (unaudited)		5
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		50
	Item 4.	Controls and Procedures		50
Part II. Other Information
	Item 1A.	Risk Factors		51
	Item 6.	Exhibits		51
Signatures				52
EX-31.1
EX-31.2
EX-32.1
EX-32.2