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 ~~June~~September 30, 2008
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 number001-33492

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)


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

2~~277~~2277 Plaza Drive, Suite 500 Sugar Land, Texas (Address of principal executive offices)		77479 (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 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” inRule12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	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 byRule 12b-2 of the Exchange Act). Yes o No þ.

There were ~~86,141,291~~86,147,125 shares of the registrant’s common stock outstanding at ~~August 13,~~November 11, 2008.

CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ONFORM 10-Q

For The Quarter Ended ~~June~~September 30, 2008


				Page No.

Part I. Financial Information
	Item 1.	Financial Statements (unaudited)			2
		Condensed Consolidated Balance Sheets — ~~June~~September 30, 2008 and December 31, 2007			2
		Condensed Consolidated Statements of Operations — Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007			3
		Condensed Consolidated Statements of Cash Flows — ~~Six~~Nine Months Ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007			4
		Notes to the Condensed Consolidated Financial Statements — ~~June~~September 30, 2008			5
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			3032
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk			6468
	Item 4.	Controls and Procedures			6568

Part II. Other Information
	Item 1.	Legal Proceedings			6670
	Item 1A.	Risk Factors			66
	~~Item 4.~~	~~Submission of Matters to a Vote of Security Holders~~			6670
	Item 6.	Exhibits			6770
Signatures					6871
Ex-10.1: ~~Second Supplement~~Amendment to ~~Environmental~~Amended and Restated Crude Oil Supply Agreement dated as of September 26, 2008, between Coffeyville Resources Refining & Marketing, LLC and J. Aron & Company.			��
Ex-10.2: Amended and Restated Settlement Deferral Letter, dated as of October 11, 2008, between Coffeyville Resources, LLC and J. Aron & Company.
Ex-10.3: First Amendment to Amended and RestatedOn-Site Product Supply Agreement, dated October 31, 2008 between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc.
Ex-10.4: Second Amendment to ~~the Company’s~~ Amended and Restated Crude Oil Supply Agreement dated as of October 31, 2008, between Coffeyville Resources Refining & Marketing, LLC and J. Aron & Company.
Ex-31.1: Certification
Ex-31.2: Certification
Ex-32.1: Certification
Ex-99.1: Risk Factors
EX-10.1: ~~SECOND SUPPLEMENT~~AMENDMENT TO ~~ENVIRONMENTAL~~AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT
EX-10.2: AMENDED AND RESTATED SETTLEMENT DEFERRAL LETTER
EX-10.3: FIRST AMENDMENT ~~AGREEMENT~~ TO ~~THE~~AMENDED AND RESTATED ON-SITE PRODUCT SUPPLY AGREEMENT
EX-10.4: SECOND AMENDMENT TO AMENDED AND RESTATED CRUDE OIL SUPPLY AGREEMENT
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-32.1: CERTIFICATION
EX-99.1: RISK FACTORS

PART I. FINANCIAL INFORMATION


ITEM 1.	*FINANCIAL STATEMENTS*

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


		June 30,		December 31,				September 30,		December 31,
		2008		2007				2008		2007
		(Unaudited)						(Unaudited)
		(In thousands of dollars)						(In thousands of dollars)

ASSETS	ASSETS						ASSETS
Current assets:
Cash and cash equivalents		$	20,616	$	30,509			$	59,862	$	30,509
Accounts receivable, net of allowance for doubtful accounts of $4,328 and $391, respectively			137,136		86,546
Accounts receivable, net of allowance for doubtful accounts of $4,332 and $391, respectively									130,086		86,546
Inventories			328,738		254,655				258,911		254,655
Prepaid expenses and other current assets			9,886		14,186				53,540		14,186
Insurance receivable			22,251		73,860				19,278		73,860
Income tax receivable			35,671		31,367				21,939		31,367
Deferred income taxes			79,996		79,047				64,295		79,047

Total current assets			634,294		570,170				607,911		570,170
Property, plant, and equipment, net of accumulated depreciation			1,189,921		1,192,174				1,185,801		1,192,174
Intangible assets, net			426		473				418		473
Goodwill			83,775		83,775				83,775		83,775
Deferred financing costs, net			6,537		7,515				6,041		7,515
Insurance receivable			58,663		11,400				35,422		11,400
Other long-term assets			5,566		2,849				6,113		2,849

Total assets		$	1,979,182	$	1,868,356			$	1,925,481	$	1,868,356


LIABILITIES AND EQUITY	LIABILITIES AND EQUITY						LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	4,849	$	4,874			$	4,837	$	4,874
Revolving debt			21,500		—
Note payable and capital lease obligations			14,683		11,640				15,100		11,640
Payable to swap counterparty			371,583		262,415				236,633		262,415
Accounts payable			163,373		182,225				192,282		182,225
Personnel accruals			36,071		36,659				19,704		36,659
Accrued taxes other than income taxes			18,710		14,732				21,666		14,732
Deferred revenue			6,995		13,161				15,359		13,161
Other current liabilities			32,014		33,820				28,731		33,820

Total current liabilities			669,778		559,526				534,312		559,526
Long-term liabilities:
Long-term debt, less current portion			481,910		484,328				480,705		484,328
Accrued environmental liabilities			4,621		4,844				4,565		4,844
Deferred income taxes			285,922		286,986				296,262		286,986
Other long-term liabilities			1,566		1,122				1,209		1,122
Payable to swap counterparty			46,723		88,230				27,903		88,230

Total long-term liabilities			820,742		865,510				810,644		865,510
Commitments and contingencies
Minority interest in subsidiaries			10,600		10,600				10,600		10,600
Stockholders’ equity
Common stock $0.01 par value per share; 350,000,000 shares authorized; 86,141,291 shares issued and outstanding			861		861				861		861
Additionalpaid-in-capital			450,492		458,359				442,700		458,359
Retained earning (deficit)			26,709		(26,500	)
Retained earnings (deficit)									126,364		(26,500	)

Total stockholders’ equity			478,062		432,720				569,925		432,720

Total liabilities and stockholders’ equity		$	1,979,182	$	1,868,356			$	1,925,481	$	1,868,356

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


													Three Months Ended						Nine Months Ended
	Three Months Ended						Six Months Ended						September 30,						September 30,
	June 30,						June 30,						2008			2007			2008			2007
	2008			2007			2008			2007						As Restated(†)						As Restated(†)
	(Unaudited)												(Unaudited)
	(In thousands except share amounts)												(In thousands except share amounts)

Net sales	$	1,512,503		$	843,413		$	2,735,506		$	1,233,896		$	1,580,911		$	585,978		$	4,316,417		$	1,819,874
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		1,287,477			569,623			2,323,671			873,293			1,440,355			453,242			3,764,026			1,326,535
Direct operating expenses (exclusive of depreciation and amortization)		62,336			60,955			122,892			174,367			56,575			44,440			179,467			218,807
Selling, general and administrative expenses (exclusive of depreciation and amortization)		14,762			14,937			28,259			28,087			(7,820	)		14,035			20,439			42,122
Net costs associated with flood		3,896			2,139			9,659			2,139			(817	)		32,192			8,842			34,331
Depreciation and amortization		21,080			17,957			40,715			32,192			20,609			10,481			61,324			42,673

Total operating costs and expenses		1,389,551			665,611			2,525,196			1,110,078			1,508,902			554,390			4,034,098			1,664,468

Operating income		122,952			177,802			210,310			123,818			72,009			31,588			282,319			155,406
Other income (expense):
Interest expense and other financing costs		(9,460	)		(15,763	)		(20,758	)		(27,620	)		(9,334	)		(18,340	)		(30,092	)		(45,960	)
Interest income		601			161			1,303			613			257			151			1,560			764
Loss on derivatives, net		(79,305	)		(155,485	)		(127,176	)		(292,444	)
Gain (loss) on derivatives, net														76,706			40,532			(50,470	)		(251,912	)
Other income, net		251			101			430			102			428			53			858			155

Total other income (expense)		(87,913	)		(170,986	)		(146,201	)		(319,349	)		68,057			22,396			(78,144	)		(296,953	)

Income (loss) before income taxes and minority interest in subsidiaries		35,039			6,816			64,109			(195,531	)		140,066			53,984			204,175			(141,547	)
Income tax expense (benefit)		4,051			(93,669	)		10,900			(140,967	)		40,411			42,731			51,311			(98,236	)
Minority interest in loss of subsidiaries		—			(419	)		—			257			—			(47	)		—			210

Net income (loss)	$	30,988		$	100,066		$	53,209		$	(54,307	)	$	99,655		$	11,206		$	152,864		$	(43,101	)

Net earnings per share
Net income per share
Basic	$	0.36					$	0.62					$	1.16					$	1.77
Diluted	$	0.36					$	0.62					$	1.16					$	1.77
Weighted average common shares outstanding
Basic		86,141,291						86,141,291						86,141,291						86,141,291
Diluted		86,158,791						86,158,791						86,158,791						86,158,791
Pro Forma Information (note 11)
Pro Forma Information (note 12)
Net income (loss) per share
Basic				$	1.16					$	(0.63	)				$	0.13					$	(0.50	)
Diluted				$	1.16					$	(0.63	)				$	0.13					$	(0.50	)
Weighted average common shares outstanding
Basic					86,141,291						86,141,291						86,141,291						86,141,291
Diluted					86,158,791						86,141,291						86,158,791						86,141,291


†		See note 2 to condensed consolidated financial statements.

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


							Nine Months Ended
	Six Months Ended						September 30,
	June 30,						2008			2007
	2008			2007						As Restated(†)
	(Unaudited)						(Unaudited)
	(In thousands of dollars)						(In thousands of dollars)

Cash flows from operating activities:
Net income (loss)	$	53,209		$	(54,307	)	$	152,864		$	(43,101	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		40,715			32,192			61,324			50,301
Provision for doubtful accounts		3,937			9			3,941			12
Amortization of deferred financing costs		989			951			1,487			1,947
Loss on disposition of fixed assets		1,550			1,155			1,550			1,246
Share-based compensation		(11,123	)		6,783			(36,892	)		11,285
Minority interest in loss of subsidiaries		—			(257	)		—			(210	)
Write-off of CVR Partners, LP initial public offering costs		2,560			—			2,539			—
Changes in assets and liabilities:
Accounts receivable		(54,527	)		(6,442	)		(47,481	)		4,160
Inventories		(71,838	)		(17,810	)		(11,373	)		(48,420	)
Prepaid expenses and other current assets		801			(164	)		(31,799	)		4,186
Insurance receivable		2,846			—			1,060			(96,382	)
Insurance proceeds from flood		1,500			—			29,500			—
Other long-term assets		(2,873	)		(1,071	)		(3,553	)		1,589
Accounts payable		(4,666	)		28,150			26,200			87,402
Accrued income taxes		(4,304	)		(101,369	)		9,428			(31,841	)
Deferred revenue		(6,166	)		(7,428	)		2,198			(2,064	)
Other current liabilities		4,839			14,620			6,123			32,309
Payable to swap counterparty		67,661			276,551			(86,109	)		230,928
Accrued environmental liabilities		(223	)		218			(279	)		209
Other long-term liabilities		444			—			87			—
Deferred income taxes		(2,013	)		(11,088	)		24,028			(37,885	)

Net cash provided by operating activities		23,318			160,693			104,843			165,671

Cash flows from investing activities:
Capital expenditures		(49,635	)		(214,053	)		(67,473	)		(239,695	)

Net cash used in investing activities		(49,635	)		(214,053	)		(67,473	)		(239,695	)

Cash flows from financing activities:
Revolving debt payments		(288,000	)		(117,000	)		(453,200	)		(241,800	)
Revolving debt borrowings		309,500			157,000			453,200			261,800
Proceeds from issuance of term debt								—			50,000
Principal payments on long-term debt		(2,443	)		(1,937	)		(3,660	)		(3,871	)
Payment of capital lease obligation		(900	)		—			(940	)		—
Payment of financing costs		—			(485	)		—			(2,526	)
Deferred costs of CVR Partners, LP initial public offering		(1,712	)		—			(2,429	)		—
Deferred costs of CVR Energy, Inc convertible debt offering		(21	)		—			(988	)		—
Deferred costs of CVR Energy, Inc. initial public offering		—			(3,060	)		—			(4,180	)

Net cash provided by financing activities		16,424			34,518
Net cash provided by (used in) financing activities								(8,017	)		59,423

Net decrease in cash and cash equivalents		(9,893	)		(18,842	)
Net increase (decrease) in cash and cash equivalents								29,353			(14,601	)
Cash and cash equivalents, beginning of period		30,509			41,919			30,509			41,919

Cash and cash equivalents, end of period	$	20,616		$	23,077		$	59,862		$	27,318

Supplemental disclosures:
Cash paid for income taxes, net of refunds (received)	$	17,216		$	(28,510	)	$	17,854		$	(28,510	)
Cash paid for interest		22,229			17,589			36,718			37,363
Non-cash investing and financing activities:
Accrual of construction in progress additions		(14,924	)		(30,085	)		(16,143	)		(31,556	)
Assets acquired through capital lease		5,097			—			4,827			—


†		See note 2 to condensed consolidated financial statements.

See accompanying notes to the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~June~~September 30, 2008

(unaudited)


(1)	Organization and History of the Company and Basis of Presentation

Organization

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date after June 24, 2005 and prior to October 16, 2007 (the date of the restructuring as further discussed in this note) are to Coffeyville Acquisition LLC (CALLC) and its subsidiaries.

The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer of high value transportation fuels in the mid-continental United States and, through a limited partnership, a producer and marketer of upgraded nitrogen fertilizer products in North America. The 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: Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (CALLC II).

Initial Public Offering of CVR Energy, Inc.

On October 26, 2007, CVR Energy, Inc. completed an initial public offering of 23,000,000 shares of its common stock. The initial public offering price was $19.00 per share.

The net proceeds to CVR from the initial public offering were approximately $408.5 million, after deducting underwriting discounts and commissions, but before deduction of other offering expenses. The Company also incurred approximately $11.4 million of other costs related to the initial public offering. The net proceeds from this offering were used to repay $280.0 million of term debt under the Company’s credit facility and to repay all indebtedness under the Company’s $25.0 million unsecured facility and $25.0 million secured facility, including related accrued interest through the date of repayment of approximately $5.9 million. Additionally, $50.0 million of net proceeds were used to repay outstanding revolving loan indebtedness under the Company’s credit facility. The balance of the net proceeds received were used for general corporate purposes.

In connection with the initial public offering, CVR became the indirect owner of the subsidiaries of CALLC and CALLC II. This was accomplished by CVR issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with the 628,667.20 for 1 stock split of CVR’s common stock and the mergers of two newly formed direct subsidiaries of CVR into Coffeyville Refining & Marketing Holdings, Inc. (Refining Holdco) and Coffeyville Nitrogen Fertilizers, Inc. (CNF). Concurrent with the merger of the subsidiaries and in accordance with a previously executed agreement, the Company’s chief executive officer received 247,471 shares of CVR common stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully vested and were exchanged at fair market value.

The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in connection with the initial public offering. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, which does not include the non-vested shares noted below.

On October 24, 2007, 17,500 shares of non-vested common stock having a value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights with respect to these shares from the date of grant. The fair value of each share of non-vested common stock was measured based on the market price of the common stock as of the date of grant and is being amortized over the respective vesting periods. One-third of the non-vested

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

award ~~will vest~~vested on October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on October 24, 2010.

Options to purchase 10,300 shares of common stock at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. These awards ~~will~~ vest over a three year service period. Fair value was measured using an option-pricing model at the date of grant.

Nitrogen Fertilizer Limited Partnership

In conjunction with the consummation of CVR’s initial public offering, CVR transferred Coffeyville Resources Nitrogen Fertilizer, LLC (CRNF), its nitrogen fertilizer business, to CVR Partners, LP (the Partnership), a newly created limited partnership, in exchange for a managing general partner interest (managing GP interest), a special general partner interest (special GP interest, represented by special GP units) and a de minimis limited partner interest (LP interest, represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to Coffeyville Acquisition III LLC ~~III~~ (CALLC III), an entity owned by CVR’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 general partner interest was $10.6 million. This interest has been reflected as minority interest in the Consolidated Balance Sheet.

CVR owns all of the interests in the Partnership (other than the managing general partner interest and the associated incentive distribution rights (IDRs)) and is entitled to all cash distributed by the Partnership. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the amended and restated partnership agreement, generated by the Partnership through December 31, 2009 has been distributed in respect of the units held by CVR and any common units issued by the Partnership if it elects to pursue an initial public offering. In addition, the Partnership and its subsidiaries are currently guarantors under the credit facility of Coffeyville Resources, LLC (CRLLC), a wholly-owned subsidiary of CVR. There will be no distributions paid with respect to the ~~IDR’s~~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, the managing general partner and various of their subsidiaries also entered into a number of agreements to regulate certain business relations between the parties.

At ~~June~~September 30, 2008, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing general partner interest and the IDRs. The managing general partner contributed assets into the Partnership in exchange for its managing general partner interest and the IDRs.

~~As of June 30, 2008,~~In accordance with the Contribution, Conveyance, and Assumption Agreement, by and between the Partnership ~~had distributed $50.0 million~~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

CVR ~~from its Adjusted Operating Surplus.~~ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

On February 28, 2008, the Partnership filed a registration statement with the Securities and Exchange Commission (SEC) to effect an initial public offering of its common units representing limited partner interests. On

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

June 13, 2008, the Company announced that the managing general partner of the Partnership had decided to postpone, indefinitely, the Partnership’s initial public offering due to then-existing market conditions for master limited partnerships. The Partnership, subsequently, withdrew the registration statement.

As of September 30, 2008, the Partnership had distributed $50.0 million to CVR.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and in accordance with the rules and regulations of the SEC. The consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interests of minority investors in its subsidiaries are recorded as minority interest. All intercompany accounts and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under GAAP have been condensed or omitted pursuant to such rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2007 audited consolidated financial statements and notes thereto included in CVR’s Annual Report onForm 10-K/A for the year ended December 31, 2007.

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 ~~June~~September 30, 2008 and December 31, 2007, the results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, and the cash flows for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007.

Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2008 or any other interim period. The preparation of financial statements in conformity with U.S. ~~generally accepted accounting principles~~GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

In connection with CVR’s initial public offering, ~~$3.1~~$4.2 million of deferred offering costs for the ~~six~~nine months ended ~~June~~September 30, 2007 were previously presented in operating activities in the interim financial statements. Such amounts have now been reflected as financing activities for the ~~six~~nine months ended ~~June~~September 30, 2007 in the accompanying Consolidated Statements of Cash Flows. The impact on the prior financial statements of this revision is not considered material.


(2)	Restatement of Financial Statements

On April 23, 2008, the Audit Committee of the Board of Directors and management of the Company concluded that the Company’s previously issued consolidated financial statements for the year ended December 31, 2007 and the related quarter ended September 30, 2007 contained errors. The Company arrived at this conclusion during the course of its closing process and review for the quarter ended March 31, 2008.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The restatement principally related to errors in the calculation of the cost of crude oil purchased by the Company and associated financial transactions. Accordingly, the Company restated the previously issued financial statements for these periods. Restated financial information, as well as a discussion of the errors and the adjustments made as a result of the restatement, are contained in the Company’s amended Annual Report on Form 10K/A for the year ended December 31, 2007. The Company did not amend the Company’s previously filed Quarterly Report onForm 10-Q for the period ended September 30, 2007.

As a result of the restatement, for the three months ended September 30, 2007, net income decreased by $2.2 million, from $13.4 million to $11.2 million. In addition, for the nine months ended September 30, 2007, net loss increased by $2.2 million from $40.9 million to $43.1 million. These changes resulted from an increase in cost of product sold (exclusive of depreciation and amortization) of $7.1 million for both periods, with an associated increase in income tax benefit of $4.9 million for both periods.

Due to the restatement, accounts payable for the quarter ended September 30, 2007 increased by $7.1 million. Income tax receivable increased by $3.0 million, current deferred income tax asset increased by $4.2 million, and long term deferred income tax liability increased by $2.3 million.

The effect of the above adjustments on the condensed consolidated financial statements is set forth in the tables below. The restatement had no effect on net cash flow from operating, investing, or financing activities as shown in the Consolidated Statements of Cash Flows. The restatement did not have any impact on the Company’s covenant compliance under its debt facilities or its cash position as of September 30, 2007.

Notes 11, 12, 16, and 17 have been restated to reflect the adjustments described above.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidated Balance Sheet Data
(in thousands)


	September 30, 2007
	Previously		Restatement
	Reported		Adjustments			As Restated

Assets
Current assets:
Cash and cash equivalents	$	27,318	$	—		$	27,318
Accounts receivable, net of allowance for doubtful accounts of $387		65,417		—			65,417
Inventories		209,853		—			209,853
Prepaid expenses and other current assets		28,190		—			28,190
Insurance receivable		84,982		—			84,982
Income tax receivable		60,937		3,003			63,940
Deferred income taxes		99,560		4,225			103,785

Total current assets		576,257		7,228			583,485

Property, plant, and equipment, net of accumulated depreciation		1,164,047		—			1,164,047
Intangible assets, net		497		—			497
Goodwill		83,775		—			83,775
Deferred financing costs, net		8,012		—			8,012
Insurance receivable		11,400		—			11,400
Other long-term assets		4,580		—			4,580

Total assets	$	1,848,568		7,228			1,855,796

Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	57,682	$	—		$	57,682
Revolving debt		20,000		—			20,000
Note payable and capital lease obligations		5,947		—			5,947
Payable to swap counterparty		241,427		—			241,427
Accounts payable		189,714		7,072			196,786
Personnel accruals		31,535		—			31,535
Accrued taxes other than income taxes		9,648		—			9,648
Deferred revenue		6,748		—			6,748
Other current liabilities		40,551		—			40,551

Total current liabilities		603,252		7,072			610,324
Long-term liabilities:
Long-term debt, less current portion		763,447		—			763,447
Accrued environmental liabilities		5,604		—			5,604
Deferred income taxes		328,785		2,349			331,134
Payable to swap counterparty		99,202		—			99,202

Total long-term liabilities		1,197,038		2,349			1,199,387
Commitments and contingencies
Minority interest in subsidiaries		5,169		—			5,169
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2007		8,656		—			8,656
Stockholders’ equity
Voting common units, 22,614,937 units issued and outstanding in 2007		29,958		(2,193	)		27,765
Management nonvoting override units, 2,976,353 units issued and outstanding in 2007		4,495					4,495

Total stockholders’ equity		34,453		(2,193	)		32,260

Total liabilities and stockholders’ equity	$	1,848,568	$	7,228		$	1,855,796

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidated Statement of Operations Data
(in thousands)


	Three Months Ended									Nine Months Ended
	September 30, 2007									September 30, 2007
	Previously			Restatement						Previously			Restatement
	Reported			Adjustments			As Restated			Reported			Adjustments			As Restated

Net Sales	$	585,978		$	—		$	585,978		$	1,819,874		$	—		$	1,819,874
Operating costs and expenses
Cost of products sold (exclusive of depreciation and amortization)		446,170			7,072			453,242			1,319,463			7,072			1,326,535
Direct operating expenses (exclusive of depreciation and amortization)		44,440			—			44,440			218,807			—			218,807
Selling, general and administrative expenses (exclusive of depreciation and amortization)		14,035			—			14,035			42,122			—			42,122
Net costs associated with flood		32,192			—			32,192			34,331			—			34,331
Depreciation and amortization		10,481			—			10,481			42,673			—			42,673

Total operating costs and expenses		547,318			7,072			554,390			1,657,396			7,072			1,664,468

Operating income		38,660			(7,072	)		31,588			162,478			(7,072	)		155,406
Other income (expense):
Interest expense and other financing costs		(18,340	)		—			(18,340	)		(45,960	)		—			(45,960	)
Interest income		151			—			151			764			—			764
Gain (loss) on derivatives, net		40,532			—			40,532			(251,912	)		—			(251,912	)
Other income, net		53			—			53			155			—			155

Total other income (expense)		22,396			—			22,396			(296,953	)		—			(296,953	)

Income (loss) before income taxes and minority interest in subsidiaries		61,056			(7,072	)		53,984			(134,475	)		(7,072	)		(141,547	)
Income tax expense (benefit)		47,610			(4,879	)		42,731			(93,357	)		(4,879	)		(98,236	)
Minority interest in loss of subsidiaries		(47	)		—			(47	)		210			—			210

Net income (loss)	$	13,399		$	(2,193	)	$	11,206		$	(40,908	)	$	(2,193	)	$	(43,101	)
Unaudited Pro Form Information (Note 12)
Net income (loss) per share
Basic	$	0.16		$	(0.03	)	$	0.13		$	(0.47	)	$	(0.03	)	$	(0.50	)
Diluted	$	0.16		$	(0.03	)	$	0.13		$	(0.47	)	$	(0.03	)	$	(0.50	)
Weighted average common shares outstanding
Basic		86,141,291						86,141,291			86,141,291						86,141,291
Diluted		86,158,791						86,158,791			86,141,291						86,141,291


(3)	Recent Accounting Pronouncements

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price).” The standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At ~~June~~September 30, 2008, the only financial assets and financial liabilities that are within the scope of SFAS 157 and measured at fair value on a recurring basis are the Company’s derivative instruments. See Note ~~14,~~15, “Fair Value Measurements.”

In February 2008, the FASB issued FASB Staff Position157-2 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). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will not have a material impact on the Company’s financial position or earnings.

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement will change the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, net earnings, and cash flows. The Company will be required to adopt this statement as of January 1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Company’s consolidated financial statements.

~~In May 2008, the FASB issued final FASB Staff Position (“FSP”) No. APB14-1,~~~~Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversions (Including Partial Cash Settlement).~~The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,~~Accounting for Derivative Instruments and Hedging Activities.~~Under the FSP, cash settled convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the liability of equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and the interim periods within those fiscal years, and will require issuers of convertible debt that can be settled in cash to record the additional expense incurred. The Company is currently evaluating the FSP in conjunction with its proposed convertible debt offering.


~~(3)~~(4)	~~Share Based~~Share-Based Compensation

Prior to CVR’s initial public offering, 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 in October 2007, 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 general partner of the Partnership to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

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

In accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair value based measurement method in accounting for share-based compensation. In accordance withEITF 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 inEITF 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 ~~June~~September 30, 2008, CVR’s common stock closing price was utilized to determine the fair value of the override units of CALLC and CALLC II. The estimated fair value per unit reflects a ratio of override units to shares of common ~~stock. The estimated fair value of~~stock in correlation with the ~~override units of CALLC III has been determined using a binomial and probability-weighted expected~~percentage for

811

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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


						*Compensation Expense Increase					*Compensation Expense Increase										*Compensation Expense Increase					*Compensation Expense Increase
	Benchmark					(Decrease) for the Three Months					(Decrease) for the Six Months					Benchmark					(Decrease) for the					(Decrease) for the Nine Months
	Value		Awards			Ended June 30,					Ended June 30,					Value		Awards			Three Months Ended September 30,					Ended September 30,
Award Type	(per Unit)		Issued		Grant Date	2008			2007		2008			2007		(per Unit)		Issued		Grant Date	2008			2007		2008			2007

Override Operating Units(a)	$	11.31		919,630	June 2005	$	(3,967	)	$	280	$	(4,525	)		565	$	11.31		919,630	June 2005	$	(748	)	$	178	$	(5,272	)		743
Override Operating Units(b)	$	34.72		72,492	December 2006		(261	)		96		(255	)		196	$	34.72		72,492	December 2006		(199	)		41		(454	)		236
Override Value Units(c)	$	11.31		1,839,265	June 2005		(3,731	)		169		(3,198	)		339	$	11.31		1,839,265	June 2005		(6,978	)		169		(10,176	)		508
Override Value Units(d)	$	34.72		144,966	December 2006		(165	)		52		(74	)		103	$	34.72		144,966	December 2006		(481	)		52		(555	)		155
Override Units(e)	$	10.00		138,281	October 2007		(2	)		—		(2	)		—	$	10.00		138,281	October 2007		—			—		(1	)		—
Override Units(f)	$	10.00		642,219	February 2008		1			—		2			—	$	10.00		642,219	February 2008		510			—		511			—

					Total	$	(8,125	)	$	597	$	(8,052	)	$	1,203					Total	$	(7,896	)	$	440	$	(15,947	)	$	1,642


*		— As CVR’s common stock price increases or decreases compensation expense increases or is reversed in correlation to such increases or decreases in the stock price subject to certain limitations.

Valuation Assumptions


(a)		In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,605,000. Significant assumptions used in the valuation were as follows:


	Grant	Remeasurement
	Date	Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule in (b) below	Based on forfeiture schedule in (b) below
Grant date fair value	$5.16 per share	N/A
~~June~~September 30, 2008 CVR closing stock price	N/A	$~~19.25~~8.52
~~June~~September 30, 2008 estimated fair value	N/A	$~~40.05~~17.54 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	N/A

912

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(b)		In accordance with SFAS 123(R), using a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections, the estimated fair value of the override operating units on December 28, 2006 was $473,000. Significant assumptions used in the valuation were as follows:


	Grant	Remeasurement
	Date	Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule below	Based on forfeiture schedule below
Grant date fair value	$8.15 per share	N/A
~~June~~September 30, 2008 CVR closing stock price	N/A	$~~19.25~~8.52
~~June~~September 30, 2008 estimated fair value	N/A	$~~20.86~~0 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	N/A

On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture as follows:


Minimum	Forfeiture
Period Held	Rate

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


(c)		In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override value units on June 24, 2005 was $4,065,000. Significant assumptions used in the valuation were as follows:


	Grant	Remeasurement
	Date	Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant date fair value	$2.91 per share	N/A
~~June~~September 30, 2008 CVR closing stock price	N/A	$~~19.25~~8.52
~~June~~September 30, 2008 estimated fair value	N/A	$~~40.05~~7.06 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	N/A

1013

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(d)		In accordance with SFAS 123(R), using a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections, the estimated fair value of the override value units on December 28, 2006 was $945,000. Significant assumptions used in the valuation were as follows:


	Grant	Remeasurement
	Date	Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant date fair value	$8.15 per share	N/A
~~June~~September 30, 2008 CVR closing stock price	N/A	$~~19.25~~8.52
~~June~~September 30, 2008 estimated fair value	N/A	$~~20.86~~0 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	N/A

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


	Subject to
Minimum	Forfeiture
~~Minimum~~ Period Held	Percentage

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


(e)		In accordance with SFAS 123(R),~~Share Based~~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. As of ~~June~~September 30, 2008 these units were fully vested. Significant assumptions used in the valuation were as follows:


Estimated forfeiture rate		None
~~June~~September 30, 2008 estimated fair value		$0.007 per share
Marketability and minority interest discount		15% discount
Volatility		36.2%


(f)		In accordance with SFAS 123(R),~~Share Based~~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. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:


Estimated forfeiture rate		None
Derived Service Period		Based on forfeiture schedule
~~June~~September 30, 2008 estimated fair value		$~~0.007~~3.77 per share
Marketability and minority interest discount		~~15%~~20% discount
Volatility		~~36.2%~~45.0%

1114

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At ~~June~~September 30, 2008, assuming no change in the estimated fair value at ~~June~~September 30, 2008, there was approximately ~~$44.1~~$8.0 million of unrecognized compensation expense related to non-voting override units. This is expected to be recognized over a remaining period of approximately three years as follows (in thousands):


	Override		Override		Override		Override
	Operating		Value		Operating		Value
	Units		Units		Units		Units

Six months ending December 31, 2008	$	2,220	$	6,468
Three months ending December 31, 2008					$	457	$	545
Year ending December 31, 2009		3,120		12,937		1,287		2,164
Year ending December 31, 2010		930		12,937		387		2,164
Year ending December 31, 2011		—		5,445		—		1,032

	$	6,270	$	37,787	$	2,131	$	5,905

Phantom Unit Appreciation Plan

The Company, through a wholly-owned subsidiary, has a Phantom Unit Appreciation Plan whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points have rights to receive distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units receive distributions. There are no other rights or guarantees, and the plan expires on July 25, 2015 or at the discretion of the compensation committee of the board of directors. As of ~~June~~September 30, 2008, the issued Profits Interest (combined phantom points and override units) represented 15% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was comprised of 11.1% and 3.9% of override interest and phantom interest, respectively. In accordance with SFAS 123(R), using the ~~June~~September 30, 2008 CVR closing common stock 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 ~~$40.05~~$17.54 and $7.06 per ~~point.~~point, respectively. CVR has recorded approximately ~~$25,961,000~~$7,984,000 and $29,217,000 in personnel accruals as of ~~June~~September 30, 2008 and December 31, 2007, respectively. Compensation expense for the three and ~~six~~nine month periods ending ~~June~~September 30, 2008 related to the Phantom Unit Appreciation Plan was reversed by ~~$(2,709,000)~~$(17,977,000) and ~~$(3,256,000)~~$(21,233,000), respectively. Compensation expense for the three and ~~six~~nine month periods ending ~~June~~September 30, 2007 was ~~$2,444,000~~$4,062,000 and ~~$5,580,000,~~$9,641,000, respectively.

At ~~June~~September 30, 2008, assuming no change in the estimated fair value at ~~June~~September 30, 2008, there was approximately ~~$15.4~~$2.9 million of unrecognized compensation expense related to the Phantom Unit Appreciation Plan. This is expected to be recognized over a remaining period of approximately three years.

Long Term Incentive Plan

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

During the quarter there were no forfeitures or vesting of stock options or non-vested shares. On ~~June 10,~~September 24, 2008, options to purchase ~~4,350~~ 9,100��shares of common stock at an exercise price of ~~$24.96~~$11.01 per share were granted to an outside director upon his election to the Company’s board of directors.

As of ~~June~~September 30, 2008, there was approximately ~~$0.1~~$0.4 million of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately one year. Compensation expense recorded for the three month periods ending ~~June~~September 30, 2008 and 2007 related to the non-vested common stock and common stock options was ~~$94,000~~$102,000 and $0, respectively. Compensation expense recorded for the ~~six~~nine month periods ending ~~June~~September 30, 2008 and 2007 related to the non-vested common stock and common stock options was ~~$185,000~~$288,000 and $0, respectively.

1215

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


~~(4)~~(5)	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 thefirst-in, first-out (FIFO) cost, or market, for fertilizer products, refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bare process, whereby raw materials and production costs are allocated towork-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):


	June 30,		December 31,		September 30,		December 31,
	2008		2007		2008		2007

Finished goods	$	145,978	$	109,394	$	110,106	$	109,394
Raw materials and catalysts		127,902		92,104		94,164		92,104
In-process inventories		28,363		29,817		27,304		29,817
Parts and supplies		26,495		23,340		27,337		23,340

	$	328,738	$	254,655	$	258,911	$	254,655


~~(5)~~(6)	Property, Plant, and Equipment

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


	June 30,		December 31,		September 30,		December 31,
	2008		2007		2008		2007

Land and improvements	$	18,588	$	13,058	$	17,672	$	13,058
Buildings		19,170		17,541		21,955		17,541
Machinery and equipment		1,277,760		1,108,858		1,288,553		1,108,858
Automotive equipment		6,269		5,171		6,448		5,171
Furniture and fixtures		7,362		6,304		7,593		6,304
Leasehold improvements		929		929		1,169		929
Construction in progress		41,498		182,046		44,527		182,046

		1,371,576		1,333,907		1,387,917		1,333,907
Accumulated depreciation		181,655		141,733		202,116		141,733

	$	1,189,921	$	1,192,174	$	1,185,801	$	1,192,174

Capitalized interest recognized as a reduction in interest expense for the three month periods ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007 totaled approximately ~~$203,000~~$244,000 and ~~$2,328,000,~~$2,877,000, respectively. Capitalized interest for the ~~six~~nine month periods ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007 totaled approximately ~~$1,321,000~~$1,565,000 and ~~$6,407,000,~~$9,285,000, respectively. Land and buildings that are under a capital lease obligation approximate ~~$5,097,000.~~$4,827,000.


~~(6)~~(7)	Planned Major Maintenance Costs

The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. The nitrogen fertilizer plant ~~last~~recently completed a major scheduled turnaround in ~~the third quarter of 2006 and is scheduled to complete a turnaround in the fourth quarter of~~October 2008. The refinery started a major scheduled turnaround in February 2007 with completion in April 2007. Costs of ~~$10,795,000 and $76,798,000~~$138,000 associated with the ~~2007 refinery~~2008 fertilizer plant turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the three and

1316

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nine months ended September 30, 2008. Costs of $0 and $76,754,000 associated with the 2007 refinery turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the three and ~~six~~nine months ending ~~June~~September 30, 2007, respectively.


~~(7)~~(8)	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 ~~$611,000~~$605,000 and ~~$577,000~~$595,000 for the three months ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 cost of product sold excludes depreciation and amortization of ~~$1,210,000~~$1,816,000 and ~~$1,197,000,~~$1,791,000, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses excludes depreciation and amortization of ~~$20,108,000~~$19,486,000 and ~~$17,089,000~~$9,582,000 for the three months ended ~~June~~September 30, 2008 and 2007, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, direct operating expenses excludes depreciation and amortization of ~~$38,811,000~~$58,296,000 and ~~$30,619,000,~~$40,202,000, respectively. Direct operating expenses also exclude depreciation of $7,627,000 for both the three and nine months ended September 30, 2007 that is included in “Net costs associated with the flood” on the condensed consolidated statement of operations as a result of assets being idled due to the flood.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of ~~$361,000~~$518,000 and ~~$291,000~~$304,000 for the three months ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, selling, general and administrative expenses excludes depreciation and amortization of ~~$694,000~~$1,212,000 and ~~$376,000,~~$680,000, respectively.


~~(8)~~(9)	Note Payable and Capital Lease Obligations

The Company entered into an insurance premium finance agreement with Cananwill, Inc. in July 2008 and July 2007 to finance the purchase of its property, liability, cargo and terrorism policies. The original ~~balance~~balances of ~~the note was~~these notes were $10.0 million and $7.6 million for 2008 and ~~required repayment~~2007, respectively. Both notes were to be repaid in ~~nine~~ equal installments with the final payment due for the 2008 note in June 2009. The balance due for the July 2007 note was paid in full in April 2008. As of September 30, 2008 and December 31, 2007 the Company owed $10.0 million and $3.4 million related to ~~this agreement. The balance due was paid in full in April 2008.~~these notes.

The Company entered into two capital leases in 2007 to lease platinum required in the manufacturing of new catalyst. The recorded lease obligations fluctuate with the platinum market price. The leases terminate on the date an equal amount of platinum is returned to each lessor, with the difference to be paid in cash. One lease was settled and terminated in January 2008. At ~~June~~September 30, 2008 and December 31, 2007 the lease obligations were recorded at approximately ~~$10.5~~$1.1 million and $8.2 million on the Consolidated Balance Sheets, respectively.

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease has an initial lease term of one year with an option to renew for three additional one-year periods. The Company has the option to purchase the property during the initial lease term or during the renewal periods if the lease is renewed. In connection with the capital lease the Company recorded a capital asset and capital lease obligation of ~~$5.1~~$4.8 million. The capital lease obligation was ~~reduced by $0.9 million payment made during the quarter resulting in a capital lease obligation of $4.2~~$4.0 million as of ~~June~~September 30, 2008.

~~(9) Flood, Crude Oil Discharge and Insurance Related Matters~~


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

On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. As a result, the Company’s refinery and nitrogen fertilizer plant were

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

severely flooded, resulting in significant damage to the refinery assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The Company maintained property damage insurance which included damage

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

caused by a flood, up to $300 million per occurrence, subject to deductibles and other limitations. The deductible associated with the property damage was $2.5 million.

Additionally, crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time to shut down and save the refinery in preparation of the flood that occurred on June 30, 2007. The Company maintained insurance policies related to environmental cleanup costs and potential liability to third parties for bodily injury or property damage. The policies were subject to a $1.0 million self-insured retention.

The Company has submitted voluminous claims information to, and continues to respond to information requests from, ~~and negotiate with,~~ the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. See Note ~~12,~~13, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007.

As of ~~June~~September 30, 2008, the Company has recorded total gross costs associated with the repair of and other matters relating to the damage to the Company’s facilities and with third party and property damage ~~remediation~~claims incurred due to the crude oil discharge of approximately ~~$153.6~~$154.6 million. Total anticipated insurance recoveries of approximately ~~$102.4~~$104.2 million have been recorded as of ~~June~~September 30, 2008 (of which ~~$21.5~~$49.5 million had already been received as of ~~June~~September 30, 2008 by the Company from insurance carriers). At ~~June~~September 30, 2008, total accounts receivable from insurance were ~~$80.9~~$54.7 million. The receivable balance is segregated between current and long-term in the Company’s Consolidated Balance Sheet in relation to the nature and classification of the items to be settled. As of ~~June~~September 30, 2008, ~~$58.7~~$35.4 million of the amounts receivable from insurers were not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset.

Management believes the recovery of the receivable from the insurance carriers is probable. While management believes that the Company’s property insurance should cover substantially all of the estimated total costs associated with the physical damage to the property, the Company’s insurance carriers have cited potential coverage limitations and defenses, which while unlikely to preclude recovery, could do so and are anticipated to delay collection for more than twelve months.

The Company’s property insurers have raised a question as to whether the Company’s facilities are principally located in “Zone A,” which was, at the time of the flood, subject to a $10 million insurance limit for flood, or “Zone B”B,” which was, at the time of the flood, subject to a $300 million insurance limit for flood. The Company has reached an agreement with certain of its property insurers representing approximately 32.5% of its total property coverage for the flood that the facilities are principally located in “Zone B” and therefore subject to the $300 million limit for the flood. The remaining property insurers have not, at this time, agreed to this position. ~~The~~In addition, the Company’s ~~primary~~excess environmental liability insurance carrier has asserted that the pollution liability claims are for “cleanup,” which is ~~subject to a $10 million sub-limit,~~not covered under its policy, rather than for “property damage,” which is covered to the limits of the policy. ~~The excess carrier has reserved its rights under the primary carrier’s position.~~ While the Company will vigorously contest the ~~primary~~excess carrier’s position, the Company contends that if that position were upheld, the Company’s umbrella ~~and excess~~ Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. On July 10, 2008, the Company filed two lawsuits against certain of its insurance carriers. One lawsuit was filed against the nonsettling property damage insurance carriers, and the second lawsuit was filed against carriers under the environmental insurance policies. The ~~lawsuits~~property insurance lawsuit involved the Zone A/Zone B issue, and the ~~cleanup,~~ pollution insurance lawsuit involved the cleanup/property damage issue described above. The Company intends to pursue the litigation vigorously. The Company’s primary pollution liability carrier has settled with the Company by paying the full $25.0 million policy limit and has been dismissed from the pollution insurance lawsuit. The $25.0 million payment from the Company’s environmental insurer is included within the $49.5 million of insurance proceeds at September 30, 2008. Considering the effect of the lawsuits, the Company continues to believe its remaining receivable as of ~~$80.9~~September 30, 2008 of $54.7 million is probable of recovery.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company’s insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Company has incurred relating to the damages and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. Because the fertilizer plant was restored to operation within this45-day period and the

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

refinery restarted its last operating unit in 48 days, a substantial portion of the lost profits incurred because of the flood cannot be claimed under insurance. The Company continues to assess its policies to determine how much, if any, of its lost profits after the45-day period are recoverable. No amounts for recovery of lost profits under the Company’s business interruption policy have been recorded in the accompanying consolidated financial statements.

The Company has recorded net pretax costs in total since the occurrence of the flood of approximately ~~$51.2~~$50.4 million associated with both the flood and related crude oil discharge as discussed in Note ~~12,~~13, “Commitments and Contingent Liabilities.” This amount is net of anticipated insurance recoveries of ~~$102.4~~$104.2 million.

Below is a summary of the gross cost associated with the flood and crude oil discharge and reconciliation of the insurance receivable (in millions):


				For the Three			For the Three		For the Six		For the Six					For the Three			For the Three			For the Nine		For the Nine
				Months Ended			Months Ended		Months Ended		Months Ended					Months Ended			Months Ended			Months Ended		Months Ended
				June 30,			June 30,		June 30,		June 30,					September 30,			September 30,			September 30,		September 30,
	Total			2008			2007		2008		2007		Total			2008			2007			2008		2007

Total gross costs incurred	$	153.6		$	(0.9	)	$	2.1	$	6.7	$	2.1	$	154.6		$	1.0		$	128.6		$	7.8	$	130.7
Total insurance receivable		(102.4	)		4.8			—		3.0		—		(104.2	)		(1.8	)		(96.4	)		1.1		(96.4	)

Net costs associated with the flood	$	51.2		$	3.9		$	2.1	$	9.7	$	2.1	$	50.4		$	(0.8	)	$	32.2		$	8.9	$	34.3


	Receivable			Receivable
	Reconciliation			Reconciliation

Total insurance receivable	$	102.4		$	104.2
Less insurance proceeds received through June 30, 2008		(21.5	)
Less insurance proceeds received through September 30, 2008					(49.5	)

Insurance receivable	$	80.9		$	54.7

Although the Company believes that it will recover substantial sums under its insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company ultimately receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements.

In 2007, the Company received insurance proceeds of $10.0 million under its property insurance policy and $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge. In the first quarter of 2008, the Company received $1.5 million under its Builder’s Risk Insurance Policy. In ~~July~~the third quarter of 2008, the Company received $13.0 million under its property insurance ~~policy.~~policy and $15.0 million was received from one environmental insurance carrier in settlement of their expected total obligation. In October 2008, the Company through certain wholly-owned subsidiaries submitted an advance payment proof of loss to certain of its insurers for unallocated property damage. The Company expects to receive an advance payment related thereto in the amount of approximately $10.1 million. As of November 6, 2008, the Company has received $9.8 million of the $10.1 million total increasing the total insurance recoveries received from $49.5 million at September 30, 2008 to $59.3 million as of November 6, 2008. The Company continues to reserve all rights under all relevant policies. See Note ~~12,~~13, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


~~(10)~~(11)	Income Taxes

The Company adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertain Tax Positions — an interpretation of FASB No. 109 (FIN 48) on January 1, 2007. The adoption of FIN 48 did not affect the Company’s financial position or results of operations. The Company does not have any unrecognized tax benefits as of ~~June~~September 30, 2008.

As of ~~June~~September 30, 2008, the Company 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 income tax return for its 2005 tax year is currently under examination. An examination of the Company’s 2004 through 2007 Texas franchise recently commenced. The Company has not been subject to any other U.S. federal or state ~~or local~~ income ~~and~~or franchise tax examinations by taxing authorities with

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

respect to other ~~tax returns. The Texas taxing authority has recently contacted the Company to inform them that they will be examining the fertilizer businesses’ Texas~~income and franchise tax ~~return for the 2004 to 2007 franchise periods.~~returns. The Company’s U.S. federal and state tax years subject to examination as of October 31, 2008 are ~~2004~~2005 to 2007. ~~As of June 30, 2008, no taxing authority has proposed any adjustments to the Company’s tax positions.~~

The Company’s effective tax rate for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 was ~~17.0%~~25.1% and ~~72.1%~~69.3%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of ~~35%~~39.9%. The effective tax rate is lower than the expected statutory tax rate for the ~~six~~nine months ended ~~June~~September 30, 2008 due primarily to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program (HPIP). The annualized effective tax rate in 2008 is lower than 2007 due to the correlation between the amount of credits projected to be generated in ~~2007~~each year in relative comparison with the projected pre-tax loss ~~levels~~level in ~~2007.~~2007 and pre-tax income level in 2008.


~~(11)~~(12)	Earnings (Loss) Per Share

On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of its common stock. Also, in connection with the initial public offering, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of the subsidiaries of CALLC and CALLC II and all of their refinery and fertilizer assets. This reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with a 628,667.20 for 1 stock split and the merger of two newly formed direct subsidiaries of CVR. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding non-vested shares issued. See Note 1, “Organization and History of the Company and Basis of Presentation”.

2008 Earnings Per Share

Earnings per share for the three and ~~six~~nine months ended ~~June~~September 30, 2008 is calculated as noted below.


	Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30, 2008						June 30, 2008						September 30, 2008						September 30, 2008
	Earnings		Shares		Per Share		Earnings		Shares		Per Share		Earnings		Shares		Per Share		Earnings		Shares		Per Share

Basic earnings per share	$	30,988,000		86,141,291	$	0.36	$	53,209,000		86,141,291	$	0.62	$	99,655,000		86,141,291	$	1.16	$	152,864,000		86,141,291	$	1.77
Diluted earnings per share	$	30,988,000		86,158,791	$	0.36	$	53,209,000		86,158,791	$	0.62	$	99,655,000		86,158,791	$	1.16	$	152,864,000		86,158,791	$	1.77

Outstanding stock options totaling ~~23,250~~32,350 common shares were excluded from the diluted earnings per share calculation for the three and ~~six~~nine months ended ~~June~~September 30, 2008 as they were antidilutive.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2007 Earnings (Loss) Per Share

The computation of basic and diluted loss per share for the three and ~~six~~nine months ended ~~June~~September 30, 2007 is calculated on a pro forma basis assuming the capital structure in place after the completion of the initial public offering was in place for the entire period.

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

Pro forma earnings (loss) per share for the three and ~~six~~nine months ended ~~June~~September 30, 2007 is calculated as noted below. For the ~~six~~nine months ended ~~June~~September 30, 2007, 17,500 non-vested shares of common stock have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive:


						For the Three Months		For the Nine Months
	For the Three Months		For the Six Months			Ended September 30,		Ended September 30,
	Ended June 30,		Ended June 30,			2007		2007
	2007		2007			As Restated(†)		As Restated(†)
	(Unaudited)		(Unaudited)			(Unaudited)		(Unaudited)

Net income (loss)	$	100,066,000	$	(54,307,000	)	$	11,206,000	$	(43,101,000	)
Pro forma weighted average shares outstanding:
Original CVR shares of common stock		100		100			100		100
Effect of 628,667.20 to 1 stock split		62,866,620		62,866,620			62,866,620		62,866,620
Issuance of shares of common stock to management in exchange for subsidiary shares		247,471		247,471			247,471		247,471
Issuance of shares of common stock to employees		27,100		27,100			27,100		27,100
Issuance of shares of common stock in the initial public offering		23,000,000		23,000,000			23,000,000		23,000,000

Basic weighted average shares outstanding		86,141,291		86,141,291			86,141,291		86,141,291
Dilutive securities — issuance of non-vested shares of common stock to board of directors		17,500		—			17,500		—

Diluted weighted average shares outstanding		86,158,791		86,141,291			86,158,791		86,141,291

Pro forma basic earnings ( loss) per share	$	1.16	$	(0.63	)
Pro forma basic earnings (loss) per share						$	0.13	$	(0.50	)
Pro forma dilutive earnings (loss) per share	$	1.16	$	(0.63	)	$	0.13	$	(0.50	)


†		See Note 2 to condensed consolidated financial statements.


~~(12)~~(13)	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		Operating			Unconditional
	Leases		Purchase Obligations		Leases			Purchase Obligations

Six months ending December 31, 2008	$	1,881	$	14,396
Three months ending December 31, 2008					$	943		$	7,455
Year ending December 31, 2009		3,293		28,723		3,293			28,685
Year ending December 31, 2010		2,169		56,256		2,169			37,526
Year ending December 31, 2011		950		54,432		950	��		56,593
Year ending December 31, 2012		198		51,827		198			53,908
Thereafter		11		378,330		11			411,263

	$	8,502	$	583,964	$	7,564		$	595,430

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. In the normal course of business, the Company also has long-term commitments to purchase services such as natural gas, electricity, water and transportation services. For the three months ended ~~June~~September 30, 2008 and 2007, lease expense totaled ~~$1,003,000~~$1,102,000 and ~~$955,000,~~$850,000, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, lease expense totaled ~~$2,074,000~~$3,176,000 and ~~$1,962,000,~~$2,812,000, 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.

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety Matters”. Liabilities related to such lawsuits are recognized when the related outcome and costs are probable and can be reasonably estimated. It is possible that 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 resolution of the Company’s 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. ~~As a result~~In connection with that discharge, the Company received in May 2008 notices of claims from sixteen private claimants under the ~~crude oil discharge, two putative class action lawsuits (one federal and one state) were~~Oil Pollution Act in aggregate amount of approximately $4.4 million. In August 2008, those claimants filed ~~seeking unspecified damages with class certification under applicable law~~suit against the Company in the United States District Court for ~~all residents, domiciliaries and property owners~~the District of ~~Coffeyville,~~ Kansas ~~who were impacted by the oil release.~~

in Wichita. The Company ~~filed~~believes that the resolution of these claims will not have a motion to dismiss the federal suit for lack of subject matter jurisdiction. On November 6, 2007, the judge in the federal class action lawsuit granted the Company’s motion to dismiss for lack of subject matter jurisdiction and no appeal was taken.

~~With respect to the state suit, the District Court of Montgomery County, Kansas conducted an evidentiary hearing~~material adverse effect on the issue of class certification on October 24 and October 25, 2007 and ruled against the class certification leaving only the original two plaintiffs. The state suit was later settled with the two original plaintiffs and the case was dismissed.consolidated financial statements.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (Consent Order) with the Environmental Protection Agency (EPA) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the 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 Company substantially completed remediating the damage caused by the crude oil discharge in July 2008 and expects any remaining minor remedial actions to be completed by December 31, 2008. The Company is currently preparing its final report to the EPA to satisfy the final requirement of the Consent Order.

As of ~~June~~September 30, 2008, the total gross costs recorded associated with remediation and third party property damage as ~~of the~~a result of the crude oil discharge ~~for obligations~~ approximated ~~$52.3~~$52.9 million. The Company has not estimated or accrued for any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from lawsuits related to the flood as management does not believe any such fines, penalties or ~~penalties assessed~~lawsuits would be material nor can be estimated.

The Company also recently received sixteen notices of claims under the Oil Pollution Act from private claimants in an aggregate amount of approximately $4.4 million. No lawsuits related to these claims have yet been filed.

While the remediation efforts were substantially completed in July 2008, the costs and damages that the Company will ultimately pay may be greater than the amounts described and projected above. Such excess costs and damages could be material to the consolidated financial statements.

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation, property damage claims, ~~cleanup,~~ resolution of class action lawsuits, and other claims brought by regulatory authorities. Our ~~primary~~excess environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup,” which is ~~subject to a $10 million sub-limit,~~not covered by such policy, rather than for “property damage,” which is covered to the limits of the policy. ~~The excess carrier has reserved its rights under the primary carrier’s position.~~ While we will vigorously contest the ~~primary~~excess carrier’s position, we contend that if that position were upheld, our umbrella ~~and~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~excess~~ 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 ~~it is probable~~ substantial sums under the environmental and liability insurance

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

policies will be recovered, the Company can not be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements. The Company received $10.0 million of insurance proceeds under its primary environmental liability insurance policy in ~~2007.~~2007 and received an additional $15.0 million in September 2008 from that carrier, which two payments together constituted full payment to the Company of the primary pollution liability policy limit.

On July 10, 2008, the Company filed two lawsuits in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the flood and crude oil discharge. One of the lawsuits was filed against the insurance carriers under the environmental policies.

Environmental, Health, and Safety (EHS) Matters

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

CVR ownsand/or operates manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.

Through Administrative Orders issued under the Resource Conservation and Recovery Act, as amended (RCRA), CVR is a potential party responsible for conducting corrective actions at its Coffeyville, Kansas and Phillipsburg, Kansas facilities. In 2005, CRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (VCPRP) to address a reported release of urea ammonium nitrate (UAN) at the Coffeyville UAN loading rack. As of ~~June~~September 30, 2008 and December 31, 2007, environmental accruals of ~~$7,150,000~~$7,079,000 and $7,646,000, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Order and the VCPRP, including amounts totaling ~~$2,529,000~~$2,514,000 and $2,802,000, respectively, included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through ~~2033,~~2031, which scope of remediation was arranged with the EPA and are discounted at the appropriate risk free rates at ~~June~~September 30, 2008 and December 31, 2007, respectively. The accruals include estimated closure and post-closure costs of ~~$1,512,000 and $1,549,000 for two~~$1,524,000

2023

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and $1,549,000 for two landfills at ~~June~~September 30, 2008 and December 31, 2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):


	Amount		Amount

Six months ending December 31, 2008		2,186
Three months ending December 31, 2008			$	1,999
Year ending December 31, 2009		687		687
Year ending December 31, 2010		1,556		1,556
Year ending December 31, 2011		313		313
Year ending December 31, 2012		313		313
Thereafter		3,282		3,282

Undiscounted total		8,337		8,150
Less amounts representing interest at 3.80%		1,187
Less amounts representing interest at 3.51%				1,071

Accrued environmental liabilities at June 30, 2008	$	7,150
Accrued environmental liabilities at September 30, 2008			$	7,079

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

The EPA has issued regulations intending to limit the amount of sulfur in diesel and gasoline. The EPA has granted the ~~Company a~~Company’s petition for a technical hardship waiver with respect to the date for compliance in meeting the sulfur-lowering standards. CVR spent approximately $16.8 million in 2007, $79.0 million in 2006 and $27.0 million in 2005 to comply with the low-sulfur rules. CVR spent ~~$8.2~~$10.1 million in the first ~~six~~nine months of 2008 and, based on information currently available, anticipates spending approximately ~~$9.7~~$6.4 million in the last ~~six~~three months of 2008, ~~and $27.3~~$41.6 million in 2009, and $5.0 million in 2010 to comply with the low-sulfur rules. The entire amounts are expected to be capitalized.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three month periods ended ~~June~~September 30, 2008 and 2007, capital expenditures were ~~$13,888,000~~$5,481,000 and ~~$35,894,000,~~$16,195,000, respectively. For the ~~six~~nine month periods ended ~~June~~September 30, 2008 and 2007, capital expenditures were ~~$29,361,000~~$34,842,000 and ~~$86,581,000,~~$102,775,000, respectively. These expenditures were incurred to improve the environmental compliance and efficiency of the operations.

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

2124

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


~~(13)~~(14)	Derivative Financial Instruments

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


	Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
	2008			2007			2008			2007			2008			2007			2008			2007

Realized loss on swap agreements	$	(52,437	)	$	(88,681	)	$	(73,953	)	$	(97,215	)	$	(33,794	)	$	(45,352	)	$	(107,747	)	$	(142,567	)
Unrealized loss on swap agreements		(15,990	)		(68,787	)		(29,896	)		(188,490	)
Realized loss on other agreements		(13,021	)		(4,824	)		(21,014	)		(7,587	)
Unrealized gain (loss) on swap agreements														98,947			90,196			69,051			(98,294	)
Realized gain (loss) on other agreements														10,811			(1,247	)		(10,203	)		(8,834	)
Unrealized gain (loss) on other agreements		(1,781	)		3,768			(625	)		(1,563	)		1,258			726			634			(837	)
Realized gain (loss) on interest rate swap agreements		(947	)		1,077			(425	)		2,317			(891	)		965			(1,316	)		3,282
Unrealized gain (loss) on interest rate swap agreements		4,871			1,962			(1,263	)		94			375			(4,756	)		(889	)		(4,662	)

Total loss on derivatives, net	$	(79,305	)	$	(155,485	)	$	(127,176	)	$	(292,444	)
Total gain (loss) on derivatives, net													$	76,706		$	40,532		$	(50,470	)	$	(251,912	)

CVR is subject to crude oil and finished goods price fluctuations caused by supply and demand conditions, weather, economic conditions, and other factors. To manage this price risk on crude oil and other inventories and to fix margins on certain future production, CVR may enter into various derivative transactions. In addition, CALLC, as further described below, entered into certain commodity derivate contracts. CVR is also subject to interest rate fluctuations. To manage interest rate risk and to meet the requirements of the credit agreements CALLC entered into an interest rate swap, as further described below as required by the long-term debt agreements.

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

Cash Flow Swap

At ~~June~~September 30, 2008, CVR’s Petroleum Segment held commodity derivative contracts (swap agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see Note ~~15,~~16, “Related Party Transactions”). The swap agreements were originally executed by CALLC on June 16, 2005 and were required under the terms of the Company’s long-term debt agreement. The notional quantities on the date of execution were 100,911,000 barrels of crude oil, 1,889,459,250 gallons of heating oil and 2,348,802,750 gallons of unleaded gasoline. The swap agreements were executed at the prevailing market rate at the time of execution. At ~~June~~September 30, 2008 the notional open amounts under the swap agreements were ~~30,070,250~~23,883,250 barrels of crude oil, ~~631,475,250~~501,548,250 gallons of heating oil and ~~631,475,250~~501,548,250 gallons of unleaded gasoline.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Rate Swap

At ~~June~~September 30, 2008, CRLLC held derivative contracts known as interest rate swap agreements that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $250,000,000. Half of the agreements are held with a related party (as described in Note ~~15,~~16, “Related Party Transactions”), and the other half

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

are held with a financial institution that is a lender under CRLLC’s long-term debt agreement. The swap agreements carry the following terms:


	Notional		Fixed
Period Covered	Amount		Interest Rate

March 31, 2008 to March 30, 2009	$	250 million		4.195	%
March 31, 2009 to March 30, 2010		180 million		4.195	%
March 31, 2010 to June ~~29,~~30, 2010		110 million		4.195	%

CVR pays the fixed rates listed above and receives a floating rate based on three-month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The swap is settled quarterly and marked-to-market at each reporting date, and all unrealized gains and losses are currently recognized in income. Transactions related to the interest rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments.


~~(14)~~(15)	Fair Value Measurements

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

The Company adopted SFAS 157 on January 1, 2008 with the exception of nonfinancial assets and nonfinancial liabilities that were deferred by FASB Staff Position157-2 as discussed in Note 23 to the Condensed Consolidated Financial Statements. As of ~~June~~September 30, 2008, the Company has not applied SFAS 157 to goodwill and intangible assets in accordance with FASB Staff Position157-2.

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


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

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

	•	Level 3 — Significant unobservable inputs (including the 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 June 30, 2008 (in thousands):~~

Level 1 Level 2 Level 3 Total

Cash Flow Swap — $ (418,306 ) — $ (418,306 )
Interest Rate Swap — (3,133 ) — (3,133 )
Other Derivative Agreements — 5,678 — 5,678

2326

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of September 30, 2008 (in thousands):


	Level 1		Level 2			Level 3		Total

Cash Flow Swap		—	$	(264,536	)		—	$	(264,536	)
Interest Rate Swap		—		(2,758	)		—		(2,758	)
Other Derivative Agreements		—		4,726			—		4,726

The Company’s derivative contracts giving rise to assets or liabilities under Level 2 are valued using pricing models based on other significant observable inputs.


~~(15)~~(16)	Related Party Transactions

Management Services Agreements

GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates VII, L.P. and related entity (Kelso) through their majority ownership of CALLC and CALLC II are majority owners of CVR.

On June 24, 2005, CALLC entered into management services agreements with each of GS and Kelso pursuant to which GS and Kelso agreed to provide CALLC with managerial and advisory services. In consideration for these services, an annual fee of $1.0 million was paid to each of GS and Kelso, plus reimbursement for any out-of-pocket expenses. The agreements terminated upon consummation of CVR’s initial public offering on October 26, 2007. Relating to the agreements, the Company recorded ~~$544,000~~$500,000 and ~~$1,082,000~~$1,582,000 in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the three and ~~six~~nine months ended ~~June~~September 30, 2007, respectively. As these agreements were terminated on October 26, 2007 there have been no expenses recorded in 2008.

Cash Flow Swap

CALLC entered into certain crude oil, heating oil and gasoline swap agreements with a subsidiary of GS, J. Aron & Company (J. Aron). Additional swap agreements with J. Aron were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in Note ~~13,~~14, “Derivative Financial Instruments”). These agreements were assigned to CRLLC on June 24, 2005. ~~Losses~~Gains totaling ~~$68,427,000~~$65,153,000 and ~~$157,468,000~~$44,844,000 were recognized related to these swap agreements for the three months ended ~~June~~September 30, 2008 and 2007, respectively, and are reflected in ~~loss~~gain (loss) on derivatives, net in the Consolidated Statements of Operations. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 the Company recognized losses of ~~$103,849,000~~$38,696,000 and ~~$285,705,000,~~$240,861,000, respectively, which are reflected in ~~loss~~gain (loss) on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at ~~June~~September 30, 2008 and December 31, 2007 includes liabilities of ~~$371,583,000~~$236,633,000 and $262,415,000, respectively, included in current payable to swap counterparty, and ~~$46,723,000~~$27,903,000 and $88,230,000, respectively, included in long-term payable to swap counterparty.

J. Aron ~~Deferral~~Deferrals

As a result of the flood and the temporary cessation of business operations in 2007, the Company entered into three separate deferral agreements for amounts owed to J. Aron. The amount deferred, excluding accrued interest, totaled $123.7 million. ~~These amounts were ultimately~~Of the original deferred ~~to August 31,~~balances, $36.2 million has been repaid as of September 30, 2008. ~~As discussed in further detail below, a portion of the deferred amounts may be further deferred until July 31, 2009.~~

These deferred payment amounts are included in the Consolidated Balance Sheet at ~~June~~September 30, 2008 in current payable to swap counterparty. The deferred balance owed to the GS subsidiary, excluding accrued interest payable, totaled ~~$123.7~~$87.5 million at ~~June~~September 30, 2008. Approximately ~~$6,210,000~~$0.5 million of accrued interest payable related to the deferred payments is included in other current liabilities at ~~June~~September 30, 2008.

On July 29, 2008, CRLLC entered into a revised letter agreement with ~~the~~ J. Aron to defer ~~further~~ $87.5 million of the deferred payment amounts under the 2007 deferral agreements. ~~The unpaid deferred amounts and all accrued and unpaid interest are due and payable in full on December 15, 2008. If~~On August 29, 2008, the Company receives proceeds, net of fees, under a convertible debt offering, in an aggregate principal amount of at least $125.0 million by December 15, 2008, the maturity date will be automatically extended to July 31, 2009 provided also that there has been no default by the Company in the performance of its obligations under the revised letter agreement. GS and Kelso each agreed to guarantee one half of the deferred payment of $87.5 million. CRLLC has agreed to repay deferred amounts equal to the sum of $36.2 million plus all accrued and unpaid interest by no later than August 31, 2008.paid

2427

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Beginning~~$36.2 million of the balance to J. Aron, as well as $7.1 million in accrued interest. Subsequent to the quarter end, the Company paid an additional $15.0 million through use of proceeds received on ~~August~~the environmental insurance policy.

The deferral agreement was further amended on October 11, 2008 and the outstanding balance of $72.5 million on that date was further deferred to July 31, 2009. Additional proceeds of $9.8 million received under the property insurance policy subsequent to October 11, 2008, ~~interest shall accrue and be payable~~were used to pay down the principle balance on the deferral amount to $62.7 million as of November 6, 2008. Under the most recent deferral, the unpaid deferred ~~amount of $87.5 million~~amounts and all accrued and unpaid interest are due and payable in full on July 31, 2009. However, all accrued interest through December 15, 2008 must be paid on that day. Interest will accrue on the amounts deferred at the rate of (i) LIBOR plus 2.75%~~. Under~~ until December 15, 2008 and (ii) LIBOR plus 5.00%-7.50% (depending on J. Aron’s cost of capital) from December 15, 2008 through the date of payment. CRLLC must make prepayments of $5.0 million for the quarters ending March 31, 2009 and June 30, 2009 to reduce the deferred amounts. To the extent that CRLLC or any of its subsidiaries receives net insurance proceeds related to the July 2007 flood that are not required to be used to prepay CRLLC’s credit agreement or be invested pursuant to the terms of ~~the deferral, the Company~~CRLLC’s credit agreement, all net insurance proceeds will be required to use the substantial majority of any gross proceeds from the pending convertible debt offering (or other debt) in excess of $125.0 million to prepay a portion of the deferred amounts. There is no certainty that the convertible debt offering will be completed. The revised agreement requires CRLLCused to prepay the deferred amounts. GS and Kelso each agreed to guarantee one half of the deferral amount ~~each quarter with the greater~~ of ~~50% of free cash flow or $5.0~~$72.5 million. ~~Failure to make the quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts.~~

Interest Rate Swap

On June 30, 2005, CALLC entered into three interest-rate swap agreements with J. Aron (as described in Note ~~13,~~14, “Derivative Financial Instruments”). ~~Gains~~Losses totaling ~~$1,962,000~~$256,000 and ~~$1,523,000~~$1,894,000 were recognized related to these swap agreements for the three months ended ~~June~~September 30, 2008 and 2007, respectively, and are reflected in ~~loss~~gain (loss) on derivatives, net in the Consolidated Statements of Operations. For the ~~six~~nine months ended ~~June 20,~~September 30, 2008 and 2007, the Company recognized losses totaling ~~$851,000~~$1,107,000 and ~~gains totaling $1,211,000,~~$683,000, respectively related to these swap agreements which are reflected in ~~loss~~gain (loss) on derivatives, net, in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at ~~June~~September 30, 2008 and December 31, 2007 includes ~~$783,000~~$786,000 and $371,000, respectively, in other current liabilities and ~~$783,000~~$590,000 and $557,000, respectively, in other long-term liabilities related to the same agreements.

Crude Oil Supply Agreement

Coffeyville Resources Refining & Marketing, LLC (CRRM), a subsidiary of the Company, is a counterparty to a crude oil supply agreement with J. Aron. Under the agreement, the parties agreed to negotiate the cost of each barrel of crude oil to be purchased from a third party, and CRRM agreed to pay J. Aron a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is adjusted further using a spread adjustment calculation based on the time period the crude oil is estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The Company recorded $0$26,407,000 and $360,000 on the Consolidated Balance Sheets at ~~June~~September 30, 2008 and December 31, 2007, respectively, in prepaid expenses and other current assets for the prepayment of crude oil. In addition, ~~$64,960,000~~$41,111,000 and $43,773,000 were recorded in inventory and ~~$17,381,000~~$24,315,000 and $42,666,000 were recorded in accounts payable at ~~June~~September 30, 2008 and December 31, 2007, respectively. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the three month periods ended ~~June~~September 30, 2008 and 2007 totaled ~~$907,915,000~~$966,006,000 and ~~$344,607,000,~~$251,958,000, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, the Company recognized expenses of ~~$1,674,128,000~~$2,640,135,000 and ~~$520,914,000,~~$772,872,000, respectively, associated with this agreement included in cost of product sold (exclusive of depreciation and amortization).

Cash and Cash Equivalents

The Company opened a highly liquid money market account with average maturities of less than 90 days within the Goldman Sachs fund family in September 2008. As of September 30, 2008, the balance in the account was approximately $51.0 million.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


~~(16)~~(17)	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 coke supply agreement that became effective October 24, 2007, is based on the lesser of a coke price derived from the ~~priced~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

price received by the fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet coke. Prior to October 25, 2007 intercompany sales were based upon a price of $15 per ton. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were ~~$2,800,000~~$3,353,000 and ~~$1,301,000~~$680,000 for the three months ended ~~June~~September 30, 2008 and 2007, respectively. Intercompany sales included in petroleum net sales were ~~$5,606,000~~$8,959,000 and ~~$1,881,000~~$2,560,000 for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, respectively.

Intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “— Nitrogen Fertilizer” was ~~$2,600,000~~$40,000 and ~~$5,189,000~~$2,593,000 for the three months ended ~~June~~September 30, 2008 and 2007, respectively. The intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under ‘‘— Nitrogen Fertilizer” was ~~$7,891,000~~$7,932,000 and ~~$8,018,000~~$10,611,000 for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, respectively.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was ~~$2,325,000~~$3,364,000 and ~~$1,116,000~~$631,000 for the three months ended ~~June~~September 30, 2008 and 2007, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was ~~$4,871,000~~$8,235,000 and ~~$1,966,000~~$2,597,000 for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, respectively.

Beginning in 2008, the Nitrogen Fertilizer Segment changed the method of classification of intercompany hydrogen sales to the Petroleum Segment. In 2008, these amounts have been reflected as “Net Sales” for the fertilizer plant. Prior to 2008, the Nitrogen Fertilizer Segment reflected these transactions as a reduction of cost of product sold (exclusive of deprecation and amortization). For the quarters ended ~~June~~September 30, 2008 and 2007, the net sales generated from intercompany hydrogen sales were ~~$2,600,000~~$40,000 and ~~$5,189,000,~~$2,593,000, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007, hydrogen sales were ~~$7,891,000~~$7,932,000 and ~~$8,018,000,~~$10,611,000, respectively. As noted above, the net sales of ~~$5,189,000~~$2,593,000 and ~~$8,018,000~~$10,611,000 were included as a reduction to the cost of product sold (exclusive of depreciation and amortization) for the three and ~~six~~nine months ended ~~June~~September 30, 2007. As these intercompany sales are eliminated, there is no financial statement impact on the consolidated financial statements.

2629

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Segment

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


													Three Months Ended						Nine Months Ended
	Three Months Ended						Six Months Ended						September 30,						September 30,
	June 30,						June 30,						2008			2007			2008			2007
	2008			2007			2008			2007						As Restated(†)						As Restated(†)
	(In thousands)						(In thousands)						(In thousands)						(In thousands)

Net sales
Petroleum	$	1,459,101		$	808,954		$	2,627,602		$	1,161,442		$	1,510,287		$	545,902		$	4,137,888		$	1,707,344
Nitrogen Fertilizer		58,802			35,760			121,401			74,335			74,155			40,756			195,557			115,091
Intersegment eliminations		(5,400	)		(1,301	)		(13,497	)		(1,881	)		(3,531	)		(680	)		(17,028	)		(2,561	)

Total	$	1,512,503		$	843,413		$	2,735,506		$	1,233,896		$	1,580,911		$	585,978		$	4,316,417		$	1,819,874

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,285,556		$	570,610		$	2,320,642		$	869,069		$	1,437,742		$	450,153		$	3,758,383		$	1,319,223
Nitrogen Fertilizer		6,846			129			15,791			6,190			6,156			3,719			21,947			9,908
Intersegment eliminations		(4,925	)		(1,116	)		(12,762	)		(1,966	)		(3,543	)		(630	)		(16,304	)		(2,596	)

Total	$	1,287,477		$	569,623		$	2,323,671		$	873,293		$	1,440,355		$	453,242		$	3,764,026		$	1,326,535

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	42,684		$	44,467		$	82,974		$	141,141		$	37,132		$	29,544		$	120,106		$	170,685
Nitrogen Fertilizer		19,652			16,488			39,918			33,226			19,443			14,896			59,361			48,122
Other		—			—			—			—			—			—			—			—

Total	$	62,336		$	60,955		$	122,892		$	174,367		$	56,575		$	44,440		$	179,467		$	218,807

Net costs associated with flood
Petroleum	$	3,369		$	2,035		$	8,902		$	2,035		$	(1,014	)	$	28,595		$	7,888		$	30,630
Nitrogen Fertilizer		34			104			17			104			10			1,892			27			1,996
Other		493			—			740			—			187			1,705			927			1,705

Total	$	3,896		$	2,139		$	9,659		$	2,139		$	(817	)	$	32,192		$	8,842		$	34,331

Depreciation and amortization
Petroleum	$	16,273		$	13,285		$	31,150		$	23,079		$	15,647		$	6,616		$	46,797		$	29,695
Nitrogen Fertilizer		4,486			4,397			8,963			8,791			4,484			3,586			13,447			12,377
Other		321			275			602			322			478			279			1,080			601

Total	$	21,080		$	17,957		$	40,715		$	32,192		$	20,609		$	10,481		$	61,324		$	42,673

Operating income (loss)
Petroleum	$	101,878		$	166,338		$	165,495		$	102,870		$	20,187		$	19,417		$	185,683		$	122,287
Nitrogen Fertilizer		23,145			11,710			49,162			21,029			46,483			13,834			95,645			34,863
Other		(2,071	)		(246	)		(4,347	)		(81	)		5,339			(1,663	)		991			(1,744	)

Total	$	122,952		$	177,802		$	210,310		$	123,818		$	72,009		$	31,588		$	282,319		$	155,406

Capital expenditures
Petroleum	$	16,589		$	104,586		$	39,130		$	211,087		$	10,235		$	24,775		$	49,364		$	235,862
Nitrogen Fertilizer		6,302			2,244			9,119			2,646			7,360			952			16,479			3,597
Other		588			(140	)		1,386			320			243			(85	)		1,630			236

Total	$	23,479		$	106,690		$	49,635		$	214,053		$	17,838		$	25,642		$	67,473		$	239,695


†		See Note 2 to condensed consolidated financial statements.

2730

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of June 30,
As of December 31,

2008 2007

Total assets
Petroleum $ 1,398,869 $ 1,277,124
Nitrogen Fertilizer 465,837 446,763
Other 114,476 144,469

Total $ 1,979,182 $ 1,868,356

Goodwill
Petroleum $ 42,806 $ 42,806
Nitrogen Fertilizer 40,969 40,969

Total $ 83,775 $ 83,775


	As of September 30,			As of December 31,
	2008			2007

Total assets
Petroleum	$	1,307,605		$	1,277,124
Nitrogen Fertilizer		620,072			446,763
Other		(2,196	)		144,469

Total	$	1,925,481		$	1,868,356

Goodwill
Petroleum	$	42,806		$	42,806
Nitrogen Fertilizer		40,969			40,969

Total	$	83,775		$	83,775


~~(17)~~(18)	Subsequent Events

~~Secondary Offering~~

~~CVR filed a registration statement~~On October 10, 2008, the Company, through its wholly-owned subsidiaries, entered into ten year agreements with Magellan Pipeline Company LP (Magellan), which agreements will allow for the ~~SEC on June 19, 2008 in which CVR’s majority stockholders and chairman planned to offer 10 million shares~~transportation of an additional 20,000 barrels per day of refined fuels from the Company’s common stock. The Company announced on July 30, 2008 that the majority stockholders elected not to proceed with the proposed secondary offering at the current time due to then-existing market conditions. The registration statement remains on file with the SEC,Coffeyville, Kansas refinery and the ~~selling stockholders may elect to proceed with~~storage of refined fuels on the ~~equity offering in the future.~~

~~SemGroup L.P Bankruptcy~~

Subsequent to June 30, 2008 SemGroup, L.P., a customer, filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. At June 30, 2008, SemGroup, L.P. owed the Company approximately $3.7 million. While the Company will seek payment of the pre-petition amount, the Company believes the likelihood of recovery is no longer probable. The receivable balance of $3.7 million was fully reserved as of June 30, 2008. The Company has no further exposure related to the bankruptcy filing of SemGroup, L.P.

~~Insurance Renewal~~

~~On July 1, 2008, we renewedand/or~~ renegotiated our primary lines of insurance including workers compensation, automobile and general liability, umbrella and excess liability, property and business interruption, cargo, terrorism and crime. Due to a combination of factors including replacement cost escalation, our outstanding claim related to the flood of June 2007 and flooding in the Midwest in the spring of 2008, the cost of these primary lines of insurance, especially with respect to property and business interruption coverage, increased substantially. For the annual period of July 1, 2008 to July 1, 2009, the cost for these primary lines of coverage increased approximately 45% to $15.7 million from $10.8 million for the annual period of July 1, 2007 to July 1, 2008. The Company entered into an insurance premium financing agreement in July 2008 to finance $10.0 million of the $15.7 million insurance premium.

~~Convertible Notes Offering~~Magellan system.

On June 19, 2008, CVR filed a registration statement with the SEC in connection with a proposed offering of $125.0 million aggregate principal amount of CVR’s Convertible Senior Notes due 2013. CVR filed an amendment to the aforementioned registration statement on ~~July~~August 25, 2008. ~~Under~~CVR requested that the proposed terms, CVR may sell up to an additional $18.75 million aggregate principal amount of notes upon exercise of an over-allotment option that CVR expects to grant to the underwriters in connection with the offering.

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

As proposed, the notes will be convertible, under certain circumstances, into cash, shares of CVR common stock or a combination of cash and shares, at CVR’s election. It is CVR’s current intent to settle the principal amount of any conversions in cash for the principal amount of the notes and a combination of cash and shares for the excess, if any, of the conversion value above the principal amount. The coupon, conversion price and other terms of the notes will be determined at the time of pricing the offering. CVR intends to use the net proceeds from the offering for general corporate purposes, which may include using a portion of the proceeds for future capital investments. Any proceeds, net of fees, in excess of $125.0 million will be used to prepay a portion of the amounts owed to J. Aron under the revised deferral agreement. A portion of the proceeds will be used to purchase government securities in an amount equal to the first six interest payments due under the notes. The government securities will be deposited into an escrow account under a pledge and escrow agreement which will secure payment of the first six scheduled interest payments on the notes.

~~There can be no assurance that any such offering will be consummated on the terms discussed in~~SEC withdraw the registration statement ~~or at all.~~on November 4, 2008. The Company will record a write-off of previously deferred costs associated with the offering of approximately $1.5 million in the fourth quarter of 2008.

On November 3, 2008, following a period of discussions with the City of Coffeyville, Kansas (the City) regarding CRNF’s electricity contract and in light of the City’s contention that CRNF had constructively terminated the contract, CRNF filed a lawsuit against the City in the District Court of Johnson County, Kansas. Under the contract CRNF must make a series of future payments for electrical generation and transmission and city margin based upon agreed upon rates. The City recently began charging a higher rate for electricity than what had been agreed to in the contract. The Company filed the lawsuit to have the contract enforced as written and to recover other damages. The Company believes that if the City is successful in the lawsuit, the higher electricity costs that it would be allowed to charge would not be material to the Company’s results of operations.

2931


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 onForm 10-Q for the quarter ended ~~June~~September 30, 2008 as well as the Company’s Annual Report onForm 10-K/A for the year ended December 31, 2007. Results of operations for the three and ~~six~~nine month periods ended ~~June~~September 30, 2008 are not necessarily indicative of results to be attained for any other period.

Forward-Looking Statements

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


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

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

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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in thisForm 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” attached hereto as Exhibit 99.1.

All forward-looking statements contained in thisForm 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 thisForm 10-Q, or to reflect the occurrence of unanticipated events.

Restatement of September 30, 2007 Financial Statements

As previously disclosed in our amended Annual Report onForm 10-K/A, the Company determined that the 2007 fiscal year financial information contained certain errors resulting from accounting errors in the third and fourth quarters of 2007. The errors arose principally from the calculation of the cost of crude oil purchased by the Company and associated transactions. We did not amend our previously filed Quarterly Report onForm 10-Q for the period ended September 30, 2007. The financial information presented in this report for September 30, 2008 contains restated information for the September 30, 2007 interim period. The effect of the restatement on our period ended September 30, 2007 is set forth in tables in Note 2 to the condensed consolidated financial statements.

Company Overview

We are an independent refiner and marketer of high value transportation fuels. In addition, we currently own all of the interests (other than the managing general partner interest and associated IDRs) in a limited partnership which produces ammonia and urea ammonia nitrate, or UAN, fertilizers. ~~At current natural gas and petroleum coke, or pet coke prices, the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America.~~

We operate under two business segments: petroleum and nitrogen fertilizer. Our petroleum business includes a 115,000 barrel per day, or bpd, complex full coking medium sour crude refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system serving central Kansas, northern Oklahoma, and southwestern Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a

145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of approximately 1.2 million barrels and (4) a rack marketing division supplying product ~~through~~into tanker trucks for distribution directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and to customers at throughput terminals on Magellan Midstream Partners L.P.’s (Magellan) refined products distribution systems. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Partners L.P. and NuStar Energy

L.P. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude variety in the world capable of being transported by pipeline.

The nitrogen fertilizer segment consists of our interest in CVR Partners, LP, a limited partnership controlled by our affiliates, which operates a nitrogen fertilizer plant and the nitrogen fertilizer business. The nitrogen fertilizer business is one of the ~~lowest~~low cost ~~producer~~producers and ~~marketer~~marketers of ammonia and UAN in North America, ~~at current~~given our use of pet coke and assuming relatively high natural gas ~~and pet coke~~ prices. The fertilizer plant is the only commercial facility in North America utilizing a coke gasification process to produce nitrogen fertilizers. The use of low cost by-product pet coke from our adjacent oil refinery as feedstock (rather than natural gas) to produce hydrogen provides the facility with a significant competitive advantage ~~given the currently~~during periods of high and volatile natural gas prices. The plant’s competition utilizes natural gas to produce ammonia. During periods of high and volatile natural gas prices, the plant is a low cost producer of fertilizer products in North America. Recognizing the fixed cost nature of our fertilizer business, the competitive advantage decreases proportionately as natural gas prices decline. With the recent decline in natural gas prices, the historic cost advantage that the plant has had is now beginning to narrow.

CVR Energy’s Initial Public Offering

On October 26, 2007 we completed an initial public offering of 23,000,000 shares of our common stock. The initial public offering price was $19.00 per share. The net proceeds to us from the sale of our common stock were approximately $408.5 million, after deducting underwriting discounts and commissions. We also incurred approximately $11.4 million of other costs related to the initial public offering. The net proceeds from the offering were used to repay $280.0 million of CVR’s outstanding term loan debt and to repay in full our $25.0 million secured credit facility and $25.0 million unsecured credit facility. We also repaid $50.0 million of indebtedness under our revolving credit facility. The balance of the net proceeds received were used for general corporate purposes.

In connection with the initial public offering, we also became the indirect owner of Coffeyville Resources, LLC (CRLLC) and all of its refinery assets. This was accomplished by CVR issuing 62,866,720 shares of its common stock to certain entities controlled by its majority stockholders pursuant to a stock split in exchange for the interests in certain subsidiaries of CALLC. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding shares of non-vested stock issued.

~~CVR Partners’ Proposed Initial Public Offering~~

On February 28, 2008, the Partnership filed a registration statement with the SEC to effect an initial public offering of 5,250,000 common units representing limited partner interests. On June 13, 2008, the Company announced that the managing general partner of the Partnership had decided to postpone, indefinitely, the Partnership’s initial public offering due to then-existing market conditions for master limited partnerships. The Partnership subsequently withdrew the registration statement

CVR Energy’s Proposed Secondary Offering

CVR filed a registration statement with the SEC on June 19, 2008 in which its majority stockholders and chairman proposed to offer 10 million shares of the Company’s common stock. The Company announced on July 30, 2008 that the majority stockholders elected not to proceed with the proposed secondary offering at that time due to then-existing market conditions. The registration statement remains on file with the SEC, and the selling stockholders may elect to proceed with the equity offering in the future.

CVR Energy’s Proposed Convertible Debt Offering

CVR filed a registration statement with the SEC on June 19, 2008 in connection with a proposed offering of $125.0 million aggregate principal amount of CVR’s Convertible Senior Notes due 2013. ~~Under~~CVR filed an amendment to this registration statement on August 25, 2008. CVR requested that the ~~proposed terms, CVR may sell up to an additional $18.75 million aggregate principal amount~~SEC withdraw the registration statement on November 4, 2008. The Company will record a write-off of ~~notes upon exercise of an over-allotment option that CVR expects to grant to the underwriters in connection~~previously deferred costs associated with the ~~offering.~~offering of approximately $1.5 million in the fourth quarter of 2008.

3133

Major Influences on Results of Operations

Petroleum Business. Our earnings and cash ~~flows~~flow 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~~feedstocks such as liquid petroleum ~~products, such as~~gas and natural gas. The prices of crude oil and ~~natural gas liquids, that are processed~~refined products have fluctuated substantially in recent periods and ~~blended into refined products.~~specifically during the three months ended September 30, 2008. The cost to acquire feedstocks, and the price for which refined products are ultimately sold, depend on market factors that are typically beyond our ~~control, including~~control. These include the overall supply of, and demand for, crude oil, ~~as well as~~ gasoline, and other refined ~~products which, in turn, depend on, among other~~products. These factors are influenced by changes in domestic and foreign ~~economies,~~economics, weather conditions, domestic and foreign political affairs, foreign and domestic production levels, the availability of imports, the marketing of competitive fuels, and the extent of government regulation. Because we applyfirst-in, first-out, or FIFO accounting to value our inventory, crude oil price movements ~~may impact net income~~can cause significant fluctuations in the ~~short term because~~valuation of ~~instantaneous changes in the value of the minimally required, unhedged on hand inventory.~~our in-process inventories and finished products in-process inventories. The effect of changes in crude oil prices on our results of operations is also influenced by the rate at which the prices of refined products adjust to reflect these changes.

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

In order to assess our operating performance, we compare our refining margin, calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), against ana widely used industry refining margin benchmark. The industry ~~refining margin is calculated by assuming~~standard that the Company uses assumes that two barrels of benchmark light sweet crude oil isare converted into one barrel of conventional gasoline and one barrel of ~~distillate.~~distillate fuel oil. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of New York Mercantile Exchange (NYMEX) gasoline and heating oil against the market value of NYMEX WTI (WTI) crude oil, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark production of gasoline and heating oil.

Crude oil ~~costs are at~~prices rose to historic ~~highs.~~highs during the first part of July 2008, but declined significantly by the end of the third quarter. These prices continued to decline in October and could have a significant impact on our net income due to the unfavorable impact expected to occur in the fourth quarter of 2008 caused by our use of the FIFO accounting method for inventory. West Texas Intermediate crude oil averaged ~~$111~~$113.52 per barrel for the ~~six~~nine months ~~ended June~~ending September 30, 2008, as compared to ~~$62~~$66.19 per barrel during the comparable period in 2007. ~~Crude oil costs continued to rise during the second quarter of 2008.~~ WTI ~~crude oil prices averaged over $134 per barrel in June 2008 and~~ spiked to ~~$140~~$145.29 per barrel on ~~June~~July 3, 2008 and moved downward to $100.64 per barrel on September 30, 2008, averaging $118.22 per barrel for the third quarter. WTI was $60.77 per barrel on November 6, 2008.

Every barrel of crude oil that we process yields approximately 88% high performance transportation fuels and distillates, and approximately 12% ~~less valuable byproducts such as pet coke, slurry~~heavy oils and ~~sulfur and volumetric~~solids. Volumetric losses (lost volume typically resulting from evaporation or some chemical change) also occur during the ~~change from liquid form to solid). Whereas~~refining process. As crude oil costs ~~have~~ increased, sales prices for many byproducts ~~have~~did not ~~increased~~increase in the same proportions, resulting in lower ~~earnings. Refined product prices have also failed to keep pace with crude oil costs.~~gross margin during the periods of rising prices.

~~In the event~~When refined product ~~sales~~ prices increase proportionally with crude oil prices, the loss on byproduct sales and volumetric loss on crude oil processed ~~are~~should be more than offset by refined fuel ~~margins, but in~~margins. With the recent crude price ~~run up~~volatility, refined fuels have failed to keep pace with crude oil costs as evidence by the narrowed 2-1-1 crack spread as a percentage of crude oil prices. For the ~~second~~third quarter of 2007 the 2-1-1 crack spread as a percentage of crude oil price was approximately ~~33.8%~~16.1% compared to ~~only 13.7%~~11.3% in the ~~second~~third quarter of 2008.

barrels subject to the Cash Flow Swap decreases from approximately ~~6.2~~6.0 million barrels per quarter to 1.5 million barrels per quarter.

~~Although~~While the 2-1-1 crack spread is a benchmark for our refinery margin, ~~because our refinery has~~we have certain feedstock costsand/or logistical advantages as compared to a benchmark ~~refinery and our~~refinery. Our product yield is less than total refinery throughput, and the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour ~~crude oil~~ that has historically cost less than WTI crude oil, a light sweet crude oil. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil to the price of WTI crude ~~oil, a light sweet crude~~ oil. The spread is referred to as our consumed crude ~~differential.~~differential, which can significantly impact our refinery margin. Our ~~refinery margin can be impacted significantly by the consumed crude differential. Our consumed crude~~ differential will move directionally with changes in the West Texas Sour (WTS) differential to WTI, and the Western Canadian Select (WCS) differential to ~~WTI as both~~WTI. Both of these differentials indicate the relative price of heavier, more sour, slate to a lighter sweet WTI. The WTI-WCS differential for the ~~second~~third quarter of 2008 was ~~$22.94~~$18.69 a barrel as compared to ~~$17.99~~$25.80 a barrel in the ~~second~~third quarter of 2007. ~~The differential for the first quarter of 2008 was $19.84 a barrel.~~ As a percentage of WTI, however, this metric averaged ~~72%~~34.3% of WTI in the 2007 period compared to ~~82%~~15.8% in the ~~second~~third quarter of 2008. The correlation between our consumed crude differential and published differentials will vary depending on the volume of light medium sour crude and heavy sour crude we purchase as a percent of our total crude ~~volume and will correlate more closely with such published differentials than the heavier and more sour the crude oil slate.~~volume.

Our petroleum business has been impacted by lower refining margins, reduced demand and our Cash Flow Swap. While improving somewhat from their recent lows, midcontinent refining margins remain below historical metrics when factoring in the high cost of crude. Increased throughput at our ~~recently expanded~~ refinery provides some offset of these factors. Historically, the strongest refining margins occur during the second and third quarters based on gasoline and diesel demand, and while crude oil prices have declined sharply from recent highs, crack spreads have not yet improved in line with the crude price declines due to continuing gasoline demand weakness.

We produce a ~~high~~significant volume of high value products, such as gasoline and distillates. Approximately 40% of our product slate is ultra low sulfur diesel, which provides us with income tax credits and is currently selling at higher margins than gasoline. Gasoline production was approximately ~~44%~~45.3% of our ~~second~~third quarter production, ~~down~~up from ~~48%~~44.4% in the ~~first~~third quarter of ~~2008.~~2007. We continue to maximize distillate production, which comprised ~~40%~~39.1% of our production in the ~~second~~third quarter of 2008 compared to ~~39%~~40.2% in the ~~first~~third quarter of ~~2008.~~2007. The balance of our production is devoted to other liquids and products, including ~~the~~ petroleum coke which is used by the nitrogen fertilizer business. We benefit from the fact that our marketing region consumes more refined products than it produces, ~~so that the~~resulting in market prices ~~of our products have to be~~ high enough to cover the logistics cost for ~~the~~ U.S. Gulf Coast refineries to ship into our ~~region.~~region to meet demand. The result of this logistical advantage ~~and the fact the actual product specification used~~of our refinery operations typically yields crack spreads that are favorable to ~~determine the NYMEX is different from the actual production in the refinery is that prices we realize are different than~~ those ~~used in determining~~depicted by the 2-1-1 ~~crack spread.~~model. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and heating oil PADD II, Group 3 vs. NYMEX basis, or heating oil basis. The Group 3 basis differential averaged ~~$0.28~~$3.65 a barrel in the ~~second~~third quarter of 2008, compared to ~~$7.83~~$9.46 a barrel in the comparable period of 2007. ~~The Group 3 basis has returned to positive territory after being negative recently, and was $4.15 per barrel on August 12, 2008, which is in line with the 3-year basis average.~~

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~~mainly of ~~electrical cost~~electricity and natural gas. We are therefore sensitive to the ~~movements~~price movement of ~~natural gas prices.~~these energy sources.

Consistent, safe, and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime ~~at our refinery~~ may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. 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 needed maintenance, feedstock costs and other factors.

Nitrogen Fertilizer Business. In the nitrogen fertilizer business, earnings and cash flow from operations are primarily affected by the relationship between nitrogen fertilizer product prices and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business uses minimal natural gas as feedstock and, as a result, is not directly impacted in terms of cost by high or volatile swings in natural gas prices. Instead, our adjacent oil refinery supplies the majority of the pet coke feedstock needed by the nitrogen fertilizer business. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the supply of, and the demand for, nitrogen fertilizer products which, in turn, depends on, among other factors, the price of natural gas, the cost and availability of fertilizer transportation infrastructure, changes in the world population, weather conditions, grain production levels, the availability of imports, and the extent of government intervention in agriculture markets. While net sales of the nitrogen fertilizer business could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and nitrogen fertilizer products sell at ~~the low,~~lower prices, high natural gas prices do not force the nitrogen fertilizer business to shut down its operations because it employs pet coke as a feedstock to produce ammonia and UAN rather than natural gas.

~~Second~~Third quarter 2008 NYMEX natural gas prices averaged ~~$11.47~~$8.99 per million Btus compared with ~~$7.66~~$6.24 per million Btus for the comparable period in 2007. This rise in natural gas prices implies a minimum increase of ~~$120~~$90.75 per ton in production costs for natural gas based North American producers ~~in an environment where~~while our production cost isremains substantially unchanged.

Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. Natural gas costs and the price of nitrogen fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade of competitors’ facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

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

The value of nitrogen fertilizer products is also an important consideration in understanding our results. The nitrogen fertilizer business generally upgrades approximately two-thirds of its ammonia production into UAN, a product that presently generates a greater value than ammonia. It takes approximately .41 tons of ammonia to produce 1 ton of 32% UAN. UAN production is a major contributor to our profitability. We continue with plans for full conversion of our ammonia product line to UAN and for expansion of total UAN capacity from 2,000 to 3,000 tons per day. In order to assess the value of nitrogen fertilizer products, we calculate netbacks, also referred to as plant gate price. Netbacks refer to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, less the costs to ship.

~~Prices~~Average prices for both ammonia and UAN for the ~~quarter~~three and nine months ended ~~June~~September 30, 2008 reflect strong ~~current~~ demand for these ~~products.~~products during the first nine months of 2008. Ammonia plant gate prices averaged ~~$528~~$685 per ton for the ~~second~~third quarter ended ~~June~~September 30, 2008, compared to ~~$366~~$363 per ton during the comparable period in 2007. UAN prices averaged ~~$303~~$324 per ton for the ~~second~~third quarter ended ~~June~~September 30, 2008, compared to ~~$218~~$234 per ton during the comparable 2007 period. ~~The prices of both ammonia~~While there has been some recent price erosion for all fertilizer products, fundamental demand drivers such as forecasted commodity grain stock to use ratios and ~~UAN continue to rise.~~estimated 2009 acres planted remain strong. Our order book as of ~~July 31,~~September 30, 2008 contains an average net back price of ammonia and UAN of ~~$760~~$786 and ~~$360~~$376 per ton, respectively. As of mid-August 2008, ammonia prices exceeded $800 per ton for prompt shipment and $1,000 per ton for spring delivery, and UAN prices have exceeded $500 per ton. Industry forecasts for the second half of 2008 and the first half of 2009 for ammonia are in the $1,075 per ton range and for UAN are in the $540 per ton range. Actual future prices will depend on supply and demand and other factors described herein.

The direct operating expense structure of the nitrogen fertilizer business is also important to its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has significantly higher fixed costs than

natural gas-based fertilizer plants. Major direct operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These costs comprise the fixed costs associated with the fertilizer plant.

The nitrogen fertilizer business generally undergoes a facility turnaround every two years. The turnaround typically lasts15-20 days and requires approximately $2-3 million in direct costs per turnaround. The ~~next~~ facility completed a scheduled turnaround in October 2008. As of September 30, 2008, $0.1 million had been incurred. It is ~~currently scheduled for~~estimated that approximately $3.1 million of costs were incurred in October associated with the ~~fourth quarter of 2008.~~turnaround.

Factors Affecting Comparability of Our Financial Results

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

2007 Flood and Crude Oil Discharge

During the weekend of June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. Our refinery and nitrogen fertilizer plant, which are located in close proximity to the Verdigris River, were severely flooded, sustained major damage and required extensive repairs.

As a result of the flooding, our refinery and nitrogen fertilizer facilities stopped operating on June 30, 2007. The refinery started operating its reformer on August 6, 2007 and began to charge crude oil to the facility on August 9, 2007. Substantially all of the refinery’s units were in operation by August 20, 2007. The nitrogen fertilizer facility, situated on slightly higher ground, sustained less damage than the refinery. The nitrogen fertilizer facility initiated startup at its production facility on July 13, 2007. Due to the down time, we experienced a significant revenue loss attributable to the property damage during the period when the facilities were not in operation. Total gross costs incurred and recorded as of ~~June~~September 30, 2008 related to the third party costs to repair the refinery and fertilizer facilities were approximately ~~$76.9~~$77.0 million and ~~$4.3~~$4.4 million, respectively.

In addition, despite our efforts to secure the refinery prior to its evacuation as a result of the flood, we estimate that 1,919 barrels (80,600 gallons) of crude oil and 226 barrels of crude oil fractions were discharged from our refinery into the Verdigris River flood waters beginning on or about July 1, 2007. We substantially completed remediating the damage caused by the crude oil discharge in July 2008 and expect any remaining minor remedial actions to be completed by December 31, 2008. In 2007, the Company ~~had~~ received insurance proceeds of $10.0 million under its property insurance policy and $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge. In the first quarter of 2008 the Company received $1.5 million under its Builders Risk Insurance Policy. In ~~July~~the third quarter of 2008, the Company received $13.0 million under its property insurance ~~policy.~~policy and $15.0 million was received from its primary environmental liability insurance carrier, which when added to the prior $10.0 million paid by that carrier, resulted in payment of the policy limit under such primary environmental liability policy of $25.0 million. As of September 30, 2008, the Company had received $49.5 million in insurance recoveries. In October 2008, the Company through certain wholly-owned subsidiaries submitted an advance payment proof of loss to certain of its insurers for unallocated property damage. The Company expects to receive an advance payment related thereto in the amount of approximately $10.1 million. As of November 6, 2008, the Company has received $9.8 million of the $10.1 million total, increasing the total insurance recoveries received from $49.5 million at September 30, 2008 to $59.3 million as of November 6, 2008.

The Company ~~also recently~~ received ~~sixteen~~in May 2008 notices of claims from sixteen private claimants under the Oil Pollution Act ~~from private claimants~~ in an aggregate amount of approximately $4.4 million. ~~No lawsuits related to~~Subsequently, in August, 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita. We believe that the resolution of these claims will not have ~~yet been filed.~~a material adverse effect on our consolidated financial statements.

As of ~~June~~September 30, 2008, the Company has recorded total gross costs associated with the repair of, and other matters relating to, the damage to the Company’s facilities and with third party and property damage remediation incurred due to the crude oil discharge of approximately ~~$153.6~~$154.6 million. Total anticipated insurance recoveries of approximately ~~$102.4~~$104.2 million have been recorded as of ~~June~~September 30, 2008 (of which ~~$21.5~~$49.5 million had already

been received as of ~~June~~September 30, 2008 by the Company from insurance carriers). At ~~June~~September 30, 2008, total accounts receivable from insurance were ~~$80.9~~$54.7 million. The receivable balance is segregated between current and long-term in the Company’s Consolidated Balance Sheet in relation to the nature and classification of the items to be settled. As of ~~June~~September 30, 2008, ~~$58.7~~$35.4 million of the amounts receivable from insurers were not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset.

Below is a summary of the gross cost arising from the flood and crude oil discharge and a reconciliation of the related insurance receivable as of ~~June~~September 30, 2008 (in millions):


				For the Three Months			For the Six Months					For the Three Months			For the Nine Months
				Ended			Ended					Ended			Ended
	Total			June 30, 2008			June 30, 2008		Total			September 30, 2008			September 30, 2008

Total gross costs incurred	$	153.6		$	(0.9	)	$	6.7	$	154.6		$	1.0		$	7.8
Total insurance receivable		(102.4	)		4.8			3.0		(104.2	)		(1.8	)		1.1

Net costs associated with the flood	$	51.2		$	3.9		$	9.7	$	50.4		$	(0.8	)	$	8.9


	Receivable			Receivable
	Reconciliation			Reconciliation

Total insurance receivable	$	102.4		$	104.2
Less insurance proceeds received		(21.5	)		(49.5	)

Insurance receivable as of June 30, 2008	$	80.9
Insurance receivable as of September 30, 2008				$	54.7

The flood significantly impacted our financial results for the third quarter of 2007 with minimal impact on our third quarter 2008 results.

Refinancing and Prior Indebtedness

In October 2007, we paid down $280.0 million of outstanding long-term debt with initial public offering proceeds. In addition, proceeds of our initial public offering were used to repay in full our $25.0 million secured credit facility, our $25.0 million unsecured credit facility and $50.0 million of indebtedness under our revolving credit facility. Our Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2008 include interest expense of ~~$9.5~~$9.3 million and ~~$20.8~~$30.1 million, respectively, on term debt of ~~$486.8~~$485.5 million. Interest expense for the three and ~~six~~nine months ended ~~June~~September 30, 2007 totaled ~~$15.8~~$18.3 million and ~~$27.6~~$46.0 million, respectively, on term debt of ~~$773.1~~$821.1 million.

J. Aron Deferrals

On July 29, 2008, ~~the Company~~CRLLC entered into a revised letter agreement with J. Aron to defer further $87.5 million of the deferred payment amounts ~~owed~~ under the 2007 deferral ~~agreements. The~~agreements to December 15, 2008. On August 29, 2008, in accordance with the additional deferral agreement, we paid $36.2 million to J. Aron, as well as $7.1 million in accrued interest as of that date resulting in a remaining balance due of $87.5 million. As of September 30, 2008, the outstanding balance due was $87.5 million and the related accrued interest was $0.5 million.

Subsequent to the September 30, 2008 quarter end, we paid an additional $15.0 million through use of proceeds received under our environmental insurance policy An Amended and Restated Settlement Deferral Letter was signed on October 11, 2008 and the remaining balance of $72.5 million at that time was further deferred until July 31, 2009. Additional insurance recoveries have been received from our property insurance carriers since the October 11, 2008 deferral. As of November 6, 2008, the principal deferral balance after the additional payments from insurance proceeds was $62.7 million.

Under this most recent deferral, the unpaid deferred amounts and all accrued and unpaid interest are due and payable in full on ~~December 15, 2008. If the Company incurs aggregate indebtedness in an aggregate principal amount of at least $125.0 million by~~July 31, 2009. However, all accrued interest through December 15, 2008 must be paid on that day. Interest will accrue on the ~~maturity~~amounts deferred at the rate of (i) LIBOR plus 2.75% until December 15, 2008 and (ii) LIBOR plus 5.00%-7.50% (depending on J. Aron’s cost of capital) from December 15, 2008 through the date of payment. CRLLC must make prepayments of $5.0 million for the quarters ending March 31, 2009 and June 30, 2009 to reduce the deferred amounts. To the extent that CRLLC or any of its subsidiaries receives net insurance proceeds related to the July 2007 flood that they are not required to use to prepay CRLLC’s credit agreement or invest pursuant to the terms of CRLLC’s credit agreement, all net insurance proceeds will be ~~automatically extended~~used to ~~July 31, 2009 provided also that there has been no default by~~prepay the ~~Company in the performance of its obligations under the revised letter agreement.~~deferred amounts. GS and Kelso each agreed to guarantee one half of the deferred payment of $87.5 million. The Company has agreed to repay deferred amounts in an amount equal to the sum of $36.2 million plus all accrued and unpaid interest ($6.7 million as of August 1, 2008) no later than August 31, 2008.obligations.

Beginning August 31, 2008, interest shall accrue and be payable on the unpaid deferred amount of $87.5 million at the rate of LIBOR plus 2.75%. Under the terms of the deferral, the Company will be required to use the substantial majority of any gross proceeds from indebtedness for borrowed money incurred by the Company or certain of its subsidiaries, including the pending convertible debt offering, in excess of $125.0 million to prepay a portion of the deferred amounts. There is no certainty that the convertible debt offering will be completed. The revised agreement requires the Company to prepay the deferred amount each quarter with the greater of 50% of free cash flow or $5.0 million. Failure to make the quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts.

Change in Reporting Entity as a Result of the Initial Public Offering

Prior to our initial public offering in October 2007, our operations were conducted by an operating partnership, ~~Coffeyville Resources, LLC.~~CRLLC. The reporting entity of the organization (CALLC) was also a partnership. Immediately prior to the closing of our initial public offering, ~~Coffeyville Resources, LLC~~CRLLC became an indirect, wholly-owned subsidiary of CVR Energy, Inc. As a result, for periods ending after October 2007, we report our results of operations and financial condition as a corporation on a consolidated basis rather than as an operating partnership.

2007 Turnaround

In April 2007, we completed a planned turnaround of our refining plant at a total cost approximating $80.4 million, which included ~~$10.8 million and~~ $76.8 million recorded in the nine month period ended September 30, 2007. No amounts were incurred for the three ~~and six month periods~~months ended ~~June~~September 30, ~~2007, respectively.~~2007. The refinery processed crude until February 11, 2007 at which time a staged shutdown of the refinery began. The refinery recommenced operations on March 22, 2007 and continually increased crude oil charge rates until all of the key units were restarted by April 23, 2007. The turnaround significantly impacted our financial results for the first and second quarter of 2007 and had no impact on our 2008 results.

Cash Flow Swap

On June 16, 2005, CALLC entered into the Cash Flow Swap with J. Aron. The Cash Flow Swap was subsequently assigned from CALLC to CRLLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately ~~58%~~57% and 14% of crude oil capacity for the periods ~~July~~October 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of executed crude oil capacity, for the period from April 1, 2008 through December 31, ~~2008. Additionally,~~2008, and we are allowed to terminate the Cash Flow Swap in 2009 and 2010, at which time the unrealized loss would become a fixed obligation. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging ~~Activities.~~Activities. Therefore, the Statement of Operations reflects all the realized and unrealized gains and losses from this swap which can create significant changes between periods. The ~~current~~recent environment of high and rising crude oil prices ~~has~~ led to higher crack spreads in absolute terms but significantly narrower crack spreads as a percentage of crude oil prices. As a result, the Cash Flow Swap, under which payments are calculated based on crack spreads in absolute terms, has had ~~and continues to have~~ a material negative impact on our ~~earnings.~~earnings through September 30, 2008. As a result of our position in the Cash Flow Swap, we paid J. Aron ~~$52.4~~$33.8 million on ~~July 8,~~October 7, 2008 with respect to the quarter ending ~~June~~September 30, 2008. For the three and ~~six~~nine months ended ~~June~~September 30, 2008 the Company recognized ~~Loss~~gain (loss) on derivatives, net, of ~~$79.3~~$76.7 million and ~~$127.2~~$(50.5) million, respectively, in the Statements of Operations, including realized and unrealized ~~loss~~gain (loss) on the Cash Flow Swap of ~~$68.4~~$65.2 million in the three months ended ~~June~~September 30, 2008 and ~~$103.8~~$(38.7) million in the ~~six~~nine months ended ~~June~~September 30, 2008. For the three and ~~six~~nine months ended ~~June~~September 30, 2007 the Company recognized a ~~Loss~~gain (loss) on derivatives, net, of ~~$155.5~~$40.5 million and ~~$292.4~~$(251.9) million, respectively, in the Statements of Operations. As of ~~June~~September 30, 2008

the Company’s Consolidated Balance Sheet reflects a payable to swap counterparty of ~~$418.3~~$264.5 million compared to $350.6 million as of December 31, 2007.

Share-Based Compensation

The Company accounts for awards under its Phantom Unit Appreciation Plan as liability based awards. In accordance with FAS 123(R), the expense associated with these awards is based on the current fair value of the awards which is derived from the Company’s stock price as remeasured at each reporting date until the awards are settled.

Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting guidance inEITF 00-12 andEITF 96-18. In accordance with that accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived from the Company’s common stock price as remeasured at each reporting

date until the awards vest. Prior to October 2007, the expense associated with the override units was based on the original grant date fair value of the awards. For the three and ~~six~~nine months ended ~~June~~September 30, 2008 the Company reduced the compensation expense by ~~$10,740,000~~$25,769,000 and ~~$11,123,000, respectively.~~$36,892,000, respectively, for all share-based compensation awards. For the three and ~~six~~nine months ended ~~June~~September 30, 2007 the Company increased compensation expense by ~~$3,041,000~~$4,502,000 and ~~$6,783,000.~~$11,285,000, respectively, for all share-based compensation awards.

Income Taxes

On an interim basis, income taxes are calculated based upon an estimated annual effective tax rate for the annual period. The estimated annual effective tax rate changes primarily due to changes in projected annual pre-tax income (loss) as estimated at each interim period and due to the significant federal and state income tax credits projected to be generated. Federal income tax credits were generated related to the production of ultra-low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program (HPIP) in 2007 and 2008. The projected income tax credits accompanied by increasing projected pre-tax loss for 2007 significantly impacted the estimated annual effective tax rate for 2007 and generated a significant increase to the income tax benefit recorded for the three months ended ~~June~~September 30, 2007. While significant income tax credits of approximately ~~$59~~$60.4 million are estimated to be generated for 2008, the estimated annual effective tax rate for 2008 is determined based upon projected pre-tax income rather than projected pre-tax loss.

Property Tax Assessments

Our results of operations for the three and ~~six~~nine months ending ~~June~~September 30, 2007 reflect minimal property tax for our fertilizer facility (due to a tax abatement). Our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2008 reflect a substantially increased property tax for our fertilizer facility, resulting from the new tax assessments by Montgomery County, Kansas with the end of a ten year tax abatement. We have appealed the assessment received in 2008 for the fertilizer facility. The refinery was reappraised in 2007 and 2008 which created a substantial increase in property tax for the refinery. We have appealed both the 2007 and 2008 assessment for the refinery and believe that tax exemptions should apply to any incremental tax which would be owed as a result of the new assessment in 2008.

Consolidation of Nitrogen Fertilizer Limited Partnership

Prior to the consummation of our initial public offering in October 2007, we transferred our nitrogen fertilizer business to the Partnership and sold the managing general partner interest in the Partnership to a new entity owned by our controlling stockholders and senior management. As of ~~June~~September 30, 2008, we own all of the interests in the Partnership (other than the managing general partner interest and associated IDRs) and are entitled to all cash that is distributed by the Partnership. The Partnership is operated by our senior management pursuant to a services agreement among us, the managing general partner and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, us, as special general partner. As special general partner of the Partnership, we have joint management rights regarding the appointment, termination and

compensation of the chief executive officer and chief financial officer of the managing general partner, have the right to designate two members to the board of directors of the managing general partner and have joint management rights regarding specified major business decisions relating to the Partnership. As of ~~June~~September 30, 2008, the Partnership had distributed ~~$50.0~~$50 million to ~~CVR from its Adjusted Operating Surplus.~~CVR.

We consolidate the Partnership for financial reporting purposes. We have determined that following the sale of the managing general partner interest to an entity owned by our controlling stockholders and senior management, the Partnership is a variable interest entity (VIE) under the provisions of FASB Interpretation No. 46R, —Consolidation of Variable Interest Entities(FIN 46R).

Using criteria in FIN 46R, management has determined that we are the primary beneficiary of the Partnership, although 100% of the managing general partner interest is owned by a new entity owned by our controlling stockholders and senior management outside our reporting structure. Since we are the primary beneficiary, the financial statements of the Partnership remain consolidated in our financial statements. The managing general partner’s interest is reflected as a minority interest on our balance sheet.

The conclusion that we are the primary beneficiary of the Partnership and required to consolidate the Partnership as a variable interest entity is based upon the fact that substantially all of the expected losses are

absorbed by the special general partner, which we own. Additionally, substantially all of the equity investment at risk was contributed on behalf of the special general partner, with nominal amounts contributed by the managing general partner. The special general partner is also expected to receive the majority, if not substantially all, of the expected returns of the Partnership through the Partnership’s cash distribution provisions.

We will need to reassess from time to time whether we remain the primary beneficiary of the Partnership in order to determine if consolidation of the Partnership remains appropriate on a going forward basis. Should we determine that we are no longer the primary beneficiary of the Partnership, we will be required to deconsolidate the Partnership in our financial statements for accounting purposes on a going forward basis. In that event, we would be required to account for our investment in the Partnership under the equity method of accounting, which would affect our reported amounts of consolidated revenues, expenses and other income statement items.

The principal events that would require the reassessment of our accounting treatment related to our interest in the Partnership include:


	•	a sale of some or all of our partnership interests to an unrelated party;

	•	a sale of the managing general partner interest to a third party;

	•	the issuance by the Partnership of partnership interests to parties other than us or our related parties; and

	•	the acquisition by us of additional partnership interests (either new interests issued by the Partnership or interests acquired from unrelated interest holders).

In addition, we would need to reassess our consolidation of the Partnership if the Partnership’s governing documents or contractual arrangements are changed in a manner that reallocates between us and other unrelated parties either (1) the obligation to absorb the expected losses of the Partnership or (2) the right to receive the expected residual returns of the Partnership.

3941

Results of Operations

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007. The summary financial data for our two operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in thisForm 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations”,~~Operations,” except for the balance sheet data as of December 31, 2007, is unaudited.


													Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended						Six Months Ended						2008			2007			2008			2007
	June 30,						June 30,									As Restated(†)						As Restated(†)
	2008			2007			2008			2007									(Unaudited)
	(Unaudited)						(Unaudited)						(Unaudited)
	(In millions, except as otherwise indicated)						(In millions, except as otherwise indicated)						(In millions, except as otherwise indicated)						(In millions, except as otherwise indicated)

Consolidated Statement of Operations Data:
Net sales	$	1,512.5		$	843.4		$	2,735.5		$	1,233.9		$	1,580.9		$	586.0		$	4,316.4		$	1,819.9
Cost of product sold (exclusive of depreciation and amortization)		1,287.4			569.6			2,323.6			873.3			1,440.3			453.2			3,764.0			1,326.6
Direct operating expenses (exclusive of depreciation and amortization)		62.3			61.0			122.9			174.4			56.6			44.5			179.5			218.8
Selling, general and administrative expenses (exclusive of depreciation and amortization)		14.8			14.9			28.3			28.1			(7.8	)		14.0			20.5			42.1
Net costs associated with flood		3.9			2.1			9.7			2.1			(0.8	)		32.2			8.8			34.3
Depreciation and amortization(1)		21.1			18.0			40.7			32.2			20.6			10.5			61.3			42.7

Operating income	$	123.0		$	177.8		$	210.3		$	123.8		$	72.0		$	31.6		$	282.3		$	155.4
Other income, net		0.9			0.3			1.8			0.7			0.7			0.2			2.5			1.0
Interest expense and other financing costs		(9.5	)		(15.8	)		(20.8	)		(27.6	)		(9.3	)		(18.3	)		(30.1	)		(46.0	)
Loss on derivatives, net		(79.3	)		(155.5	)		(127.2	)		(292.4	)
Gain (loss) on derivatives, net														76.7			40.5			(50.5	)		(251.9	)

Income (loss) before income taxes and minority interest in subsidiaries	$	35.1		$	6.8		$	64.1		$	(195.5	)	$	140.1		$	54.0		$	204.2		$	(141.5	)
Income tax (expense) benefit		(4.1	)		93.7			(10.9	)		141.0			(40.4	)		(42.7	)		(51.3	)		98.2
Minority interest in (income) loss of subsidiaries		—			(0.4	)		—			0.2			—			(0.1	)		—			0.2

Net income (loss)(2)	$	31.0		$	100.1		$	53.2		$	(54.3	)	$	99.7		$	11.2		$	152.9		$	(43.1	)
Earnings per share, basic	$	0.36					$	0.62					$	1.16					$	1.77
Earnings per share, diluted	$	0.36					$	0.62					$	1.16					$	1.77
Weighted average shares, basic		86,141,291						86,141,291						86,141,291						86,141,291
Weighted average shares, diluted		86,158,791						86,158,791						86,158,791						86,158,791
Pro forma earnings (loss) per share, basic				$	1.16					$	(0.63	)				$	0.13					$	(0.50	)
Pro forma earnings (loss) per share, diluted				$	1.16					$	(0.63	)				$	0.13					$	(0.50	)
Pro forma weighted average shares, basic					86,141,291						86,141,291						86,141,291						86,141,291
Pro forma weighted average shares, diluted					86,158,291						86,141,291						86,158,791						86,141,291

4042


	As of June 30,			As of December 31,		As of September 30,		As of September 31,
	2008			2007		2008		2007
	(Unaudited)					(Unaudited)
	(In millions, except as otherwise indicated)					(In millions, except as otherwise indicated)

Balance Sheet Data:
Cash and cash equivalents	$	20.6		$	30.5	$	59.9	$	30.5
Working capital		(35.5	)		10.7		73.6		10.7
Total assets		1,979.2			1,868.4		1,925.5		1,868.4
Total debt, including current portion		522.9			500.8		500.6		500.8
Minority interest in subsidiaries		10.6			10.6		10.6		10.6
Stockholders’ equity		478.1			432.7		569.9		432.7


													Three Months Ended						Nine Months Ended
	Three Months Ended						Six Months Ended						September 30,						September 30,
	June 30,						June 30,						2008			2007			2008			2007
	2008			2007			2008			2007						As Restated(†)						As Restated(†)
	(Unaudited)						(Unaudited)						(Unaudited)						(Unaudited)
	(In millions)						(In millions)						(In millions)						(In millions)

Other Financial Data:
Depreciation and amortization	$	21.1		$	18.0		$	40.7		$	32.2		$	20.6		$	10.5		$	61.3		$	42.7
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(3)		40.6			141.5			71.2			59.0			40.2			(43.0	)		111.4			16.0
Cash flows (used in) provided by operating activities		(0.8	)		116.6			23.3			160.7
Cash flows provided by operating activities														81.5			5.0			104.8			165.7
Cash flows (used in) investing activities		(23.5	)		(106.7	)		(49.6	)		(214.1	)		(17.8	)		(25.6	)		(67.4	)		(239.7	)
Cash flows provided by financing activities		19.8			5.6			16.4			34.5
Cash flows provided by (used in) financing activities														(24.4	)		24.9			(8.0	)		59.4
Capital expenditures for property, plant and equipment		23.5			106.7			49.6			214.1			17.8			25.6			67.4			239.7


	Three Months Ended				Six Months Ended								Nine Months Ended
	June 30,				June 30,				Three Months Ended September 30,				September 30,
	2008		2007		2008		2007		2008		2007		2008		2007

Key Operating Statistics:
Petroleum Business
Production (barrels per day)(4)		119,532		102,237		122,573		78,098		132,210		58,382		125,811		71,454
Crude oil throughput (barrels per day)(4)		104,558		94,667		105,544		71,098		114,678		52,497		108,611		64,829
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)(5)		79.5		82.8		163.2		169.0		110.3		75.9		273.5		244.9
UAN (tons in thousands)		139.1		138.9		289.2		304.6		172.8		128.0		462.0		432.6


†		See note 2 to condensed consolidated financial statements.


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


	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
	June 30,				June 30,				September 30,				September 30,
	2008		2007		2008		2007		2008		2007		2008		2007
	(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)
	(In millions)				(In millions)				(In millions)				(In millions)

Depreciation and amortization excluded from cost of product sold	$	0.6	$	0.6	$	1.2	$	1.2	$	0.6	$	0.6	$	1.8	$	1.8
Depreciation and amortization excluded from direct operating expenses		20.1		17.1		38.8		30.6		19.5		9.6		58.3		40.2
Depreciation and amortization excluded from selling, general and administrative expenses		0.4		0.3		0.7		0.4		0.5		0.3		1.2		0.7
Depreciation included in net costs associated with the flood										—		7.6		—		7.6

Total depreciation and amortization	$	21.1	$	18.0	$	40.7	$	32.2	$	20.6	$	18.1	$	61.3	$	50.3


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


	Three Months Ended				Six Months Ended				Three Months Ended						Nine Months Ended
	June 30,				June 30,				September 30,						September 30,
	2008		2007		2008		2007		2008			2007			2008			2007
	(Unaudited)				(Unaudited)				(Unaudited)						(Unaudited)
	(In millions)				(In millions)				(In millions)						(In millions)

Funded letter of credit expense and interest rate swap not included in interest expense(a)	$	2.4	$	0.2	$	3.3	$	0.2	$	2.3		$	0.7		$	5.6		$	0.9
Major scheduled turnaround expense(b)		—		10.8		—		76.8		0.1			—			0.1			76.8
Unrealized net loss from Cash Flow Swap		16.0		68.8		29.9		188.5
Unrealized net (gain) loss from Cash Flow Swap										(98.9	)		(90.2	)		(69.1	)		98.3


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

(b)		Represents expenses associated with a major scheduled turnaround atfor the ~~refinery.~~fertilizer facility in October 2008 and for the refinery in 2007.


(3)		Net income (loss) adjusted for unrealized loss (net) from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the acquisition of Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC (CALLC) on June 24, 2005. On June 16, 2005, ~~Coffeyville Acquisition LLC~~CALLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from ~~Coffeyville Acquisition LLC~~CALLC to ~~Coffeyville Resources, LLC~~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 ~~58%~~57% and 14% of crude oil capacity for the periods ~~July~~October 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of executed crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, at which time the unrealized loss would become a fixed obligation.

		We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect in each period material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which are accounted for as a liability on our balance sheet. As the absolute crack spreads


		increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our Statements of Operations. Conversely, as absolute crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business and assessing its growth and profitability from a strategic and financial planning perspective, management and our board of directors considers our U.S. GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized gain or loss from Cash Flow Swap net of its related tax benefit.


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

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


													Three Months Ended					Nine Months Ended
	Three Months Ended						Six Months Ended						September 30,					September 30,
	June 30,						June 30,						2008		2007			2008		2007
	2008			2007			2008			2007					As Restated(†)					As Restated(†)
	(Unaudited)						(Unaudited)						(Unaudited)					(Unaudited)

Net income (loss) adjusted for unrealized loss from Cash Flow Swap	$	40.6		$	141.5		$	71.2		$	59.0		$	40.2	$	(43.0	)	$	111.4	$	16.0
Plus:
Unrealized (loss) from Cash Flow Swap, net of taxes		(9.6	)		(41.4	)		(18.0	)		(113.3	)
Unrealized gain (loss) from Cash Flow Swap, net of taxes														59.5		54.2			41.5		(59.1	)

Net income (loss)	$	31.0		$	100.1		$	53.2		$	(54.3	)	$	99.7	$	11.2		$	152.9	$	(43.1	)


†		See note 2 to condensed consolidated financial statements.

(4)		Barrels per day are calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facility’s continuous operations.

(5)		The tons produced for ammonia represent the total ammonia produced including ammonia produced that was upgraded into UAN. The net tons produced that could be sold were 39.0, 23.9, 83.3 and 68.8 for the three months ended September 30, 2008 and 2007 and the nine months ended September 30, 2008 and 2007, respectively.

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


									Three Months Ended					Nine Months Ended
	Three Months Ended				Six Months Ended				September 30,					September 30,
	June 30,				June 30,				2008			2007		2008		2007
	2008		2007		2008		2007					As Restated(†)				As Restated(†)
	(Unaudited)				(Unaudited)				(Unaudited)					(Unaudited)
	(In millions, except as otherwise indicated)				(In millions, except as otherwise indicated)				(In millions, except as otherwise indicated)					(In millions, except as otherwise indicated)

Petroleum Business Financial Results:
Net sales	$	1,459.1	$	809.0	$	2,627.6	$	1,161.4	$	1,510.3		$	545.9	$	4,137.9	$	1,707.3
Cost of product sold (exclusive of depreciation and amortization)		1,285.6		570.6		2,320.6		869.1		1,437.7			450.2		3,758.4		1,319.2
Direct operating expenses (exclusive of depreciation and amortization)		42.7		44.5		83.0		141.1		37.1			29.5		120.1		170.7
Net costs associated with flood		3.4		2.0		8.9		2.0		(1.0	)		28.6		7.9		30.6
Depreciation and amortization		16.3		13.3		31.2		23.1		15.6			6.6		46.8		29.7

Gross profit	$	111.1	$	178.6	$	183.9	$	126.1	$	20.9		$	31.0	$	204.7	$	157.1
Plus direct operating expenses (exclusive of depreciation and amortization)		42.7		44.5		83.0		141.1		37.1			29.5		120.1		170.7
Plus net costs associated with flood		3.4		2.0		8.9		2.0		(1.0	)		28.6		7.9		30.6
Plus depreciation and amortization		16.3		13.3		31.2		23.1		15.6			6.6		46.8		29.7

Refining margin(1)	$	173.5	$	238.4	$	307.0	$	292.3	$	72.6		$	95.7	$	379.5	$	388.1
Refining margin per crude oil throughput barrel(1)	$	18.23	$	27.67	$	15.98	$	22.71	$	6.88		$	19.81	$	12.75	$	21.93
Gross profit per crude oil throughput barrel	$	11.68	$	20.73	$	9.57	$	9.80	$	1.98		$	6.42	$	6.88	$	8.88
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel	$	4.49	$	5.17	$	4.32	$	10.96	$	3.52		$	6.11	$	4.04	$	9.64
Operating income		101.9		166.3		165.5		102.9		20.2			19.4		185.7		122.3


†		See note 2 to condensed consolidated financial statements.

(1)		Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our 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.

Three Months Ended
Six Months Ended

June 30, June 30,
2008 2007 2008 2007
(Dollars per barrel) (Dollars per barrel)

Market Indicators:

West Texas Intermediate (WTI) crude oil $ 123.80 $ 65.02 $ 111.12 $ 61.67
NYMEX 2-1-1 Crack Spread 17.02 22.00 14.48 17.13
Crude Oil Differentials:
WTI less WTS (sour) 4.62 4.70 4.63 4.43
WTI less WCS (heavy sour) 22.94 17.99 21.52 16.39
WTI less Dated Brent (foreign) 2.61 (3.73 ) 2.07 (1.54 )
PADD II Group 3 Basis:
Gasoline (3.61 ) 5.45 (2.56 ) 2.59
Heating Oil 4.17 10.20 3.91 9.54
PADD II Group 3 Crack:
Gasoline 5.84 34.21 5.43 23.42
Heating Oil 28.76 25.45 24.88 22.97
Company Operating Statistics:

Per barrel profit, margin and expense of crude oil throughput:
Refining margin $ 18.23 $ 27.67 $ 15.98 $ 22.71
Gross profit 11.68 20.73 9.57 9.80
Direct operating expenses (exclusive of depreciation and amortization) 4.49 5.17 4.32 10.96
Per gallon sales price:
Gasoline 3.12 2.42 2.77 2.09
Distillate 3.66 2.15 3.26 2.03

Three Months Ended June 30, Six Months Ended June 30,
2008 2007 2008 2007
Barrels
Barrels
Barrels
Barrels

per Day % per Day % per Day % per Day %

Volumetric Data

Production:
Total gasoline 52,028 43.5 40,350 39.5 55,845 45.6 31,971 41.0
Total distillate 48,168 40.3 43,091 42.1 48,379 39.4 32,592 41.7
Total other 19,336 16.2 18,796 18.4 18,349 15.0 13,535 17.3

Total all production 119,532 100.0 102,237 100.0 122,573 100.0 78,098 100.0
Crude oil throughput 104,558 91.7 94,667 96.1 105,544 90.3 71,098 95.0
All other inputs 9,404 8.3 3,811 3.9 11,300 9.7 3,763 5.0

Total feedstocks 113,962 100.0 98,478 100.0 116,844 100.0 74,861 100.0

4446

Three Months Ended June 30, Six Months Ended June 30,
2008 2007 2008 2007
Total
Total
Total
Total

Barrels % Barrels % Barrels % Barrels %

Crude oil throughput by crude oil type:
Sweet 6,784,064 71.3 5,582,320 64.8 13,350,256 69.5 8,362,963 65.0
Light/medium sour 1,798,300 18.9 2,618,866 30.4 3,592,083 18.7 4,092,254 31.8
Heavy sour 932,452 9.8 413,505 4.8 2,266,662 11.8 413,505 3.2

Total crude oil throughput 9,514,816 100.0 8,614,692 100.0 19,209,001 100.0 12,868,722 100.0


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008			2007
			As Restated(†)					As Restated†
	(Dollars per barrel)				(Dollars per barrel)

Market Indicators:
West Texas Intermediate (WTI) crude oil	$	118.22	$	75.15	$	113.52		$	66.19
NYMEX 2-1-1 Crack Spread		13.33		12.12		14.09			15.45
Crude Oil Differentials:
WTI less WTS (sour)		2.31		5.16		3.84			4.63
WTI less WCS (heavy sour)		18.69		25.80		20.58			19.54
WTI less Dated Brent (foreign)		3.13		0.40		2.41			(0.93	)
PADD II Group 3 Basis:
Gasoline		2.62		8.78		(0.81	)		4.68
Heating Oil		4.68		10.14		4.17			9.77
PADD II Group 3 Crack:
Gasoline		8.52		20.57		6.47			22.48
Heating Oil		25.43		22.58		25.07			22.86
Company Operating Statistics:
Per gallon sales price:
Gasoline		3.06		2.28		2.87			2.14
Distillate		3.45		2.35		3.33			2.12


†		See note 2 to condensed consolidated financial statements.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2008				2007				2008				2007
	Barrels				Barrels				Barrels				Barrels
	per Day		%		per Day		%		per Day		%		per Day		%

Volumetric Data
Production:
Total gasoline		59,864		45.3		25,971		44.4		57,195		45.5		29,949		41.9
Total distillate		51,744		39.1		23,448		40.2		49,509		39.3		29,511		41.3
Total other		20,602		15.6		8,963		15.4		19,107		15.2		11,994		16.8

Total all production		132,210		100.0		58,382		100.0		125,811		100.0		71,454		100.0
Crude oil throughput		114,678		90.7		52,497		93.9		108,611		90.5		64,829		94.7
All other inputs		11,755		9.3		3,403		6.1		11,453		9.5		3,643		5.3

Total feedstocks		126,433		100.0		55,900		100.0		120,064		100.0		68,472		100.0


	Three Months Ended September 30,								Nine Months Ended September 30,
	2008				2007				2008				2007
	Total				Total				Total				Total
	Barrels		%		Barrels		%		Barrels		%		Barrels		%

Crude oil throughput by crude oil type:
Sweet		8,484,339		80.4		2,835,032		58.7		21,834,595		73.4		11,203,099		63.3
Light/medium sour		1,035,395		9.8		1,168,786		24.2		4,627,478		15.5		5,256,430		29.7
Heavy sour		1,030,603		9.8		825,878		17.1		3,297,265		11.1		1,238,889		7.0

Total crude oil throughput		10,550,337		100.0		4,829,696		100.0		29,759,338		100.0		17,698,418		100.0

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,				Three Months Ended				Nine Months Ended
	2008		2007		2008		2007		September 30,				September 30,
	(Unaudited)				(Unaudited)				2008		2007		2008		2007
					(In millions, except as otherwise indicated)				(Unaudited)				(Unaudited)
	(In millions, except as otherwise indicated)								(In millions, except as otherwise indicated)

Nitrogen Fertilizer Business Financial Results:
Net sales	$	58.8	$	35.8	$	121.4	$	74.3	$	74.2	$	40.8	$	195.6	$	115.1
Cost of product sold (exclusive of depreciation and amortization)		6.8		0.1		15.8		6.2		6.2		3.7		21.9		9.9
Direct operating expenses (exclusive of depreciation and amortization)		19.7		16.5		39.9		33.2		19.4		14.9		59.4		48.1
Net cost associated with flood		—		0.1		—		0.1		—		1.9		—		2.0
Depreciation and amortization		4.5		4.4		9.0		8.8		4.5		3.6		13.4		12.4
Operating income		23.1		11.7		49.2		21.0		46.5		13.8		95.6		34.9


	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
	June 30,				June 30,				September 30,				September 30,
	2008		2007		2008		2007		2008		2007		2008		2007

Market Indicators (unaudited)
Natural gas (dollars per MMBtu)	$	11.47	$	7.66	$	10.14	$	7.41	$	8.99	$	6.24	$	9.75	$	7.02
Ammonia — Southern Plains (dollars per ton)		678		400		634		395		936		388		735		393
UAN — Corn Belt (dollars per ton)		411		290		391		265		506		298		429		276


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Company Operating Statistics (unaudited)
Production (thousand tons):
Ammonia(1)		110.3			75.9			273.5			244.9
UAN		172.8			128.0			462.0			432.6

Total		283.1			203.9			735.5			677.5
Sales (thousand tons)(2):
Ammonia		21.9			24.7			65.2			58.8
UAN		165.4			120.6			462.0			414.2

Total		187.3			145.3			527.2			473.0
Product pricing (plant gate) (dollars per ton)(2):
Ammonia	$	685		$	363		$	568		$	358
UAN		324			234			296			203
On-stream factor(3):
Gasification		98.5	%		81.3	%		91.1	%		87.4	%
Ammonia		97.8	%		80.4	%		89.6	%		84.6	%
UAN		94.8	%		71.8	%		86.4	%		78.5	%
Reconciliation to net sales (dollars in thousands):
Freight in revenue	$	5,562		$	3,581		$	13,634		$	10,011
Hydrogen revenue		40			—			7,932			—
Sales net plant gate		68,553			37,175			173,991			105,080

Total net sales		74,155			40,756			195,557			115,091

4548

Three Months Ended
Six Months Ended

June 30, June 30,
2008 2007 2008 2007

Company Operating Statistics (unaudited)

Production (thousand tons):
Ammonia 79.5 82.8 163.2 169.0
UAN 139.1 138.9 289.2 304.6

Total 218.6 221.7 452.4 473.6
Sales (thousand tons)(1):
Ammonia 19.1 13.4 43.3 34.1
UAN 138.6 126.8 296.6 293.5

Total 157.7 140.2 339.9 327.6
Product pricing (plant gate) (dollars per ton)(1):
Ammonia $ 528 $ 366 $ 509 $ 354
UAN 303 218 281 190
On-stream factor(2):
Gasification 82.8 % 89.3 % 87.3 % 90.6 %
Ammonia 80.0 % 87.4 % 85.4 % 86.8 %
UAN 78.3 % 74.4 % 82.1 % 81.9 %
Reconciliation to net sales (dollars in thousands):
Freight in revenue $ 4,050 $ 3,291 $ 8,072 $ 6,430
Hydrogen revenue 2,600 — 7,891 —
Sales net plant gate 52,152 32,469 105,438 67,905

Total net sales 58,802 35,760 121,401 74,335


(1)		The tons produced for ammonia represent the total ammonia produced including ammonia produced that was upgraded into UAN. The net tons produced that could be sold were 39.0, 23.9, 83.3 and 68.8 for the three months ended September 30, 2008 and 2007 and the nine months ended September 30, 2008 and 2007, respectively.

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

~~(2)~~(3)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.

Three Months Ended ~~June~~September 30, 2008 Compared to the Three Months Ended ~~June~~September 30, 2007

Consolidated Results of Operations

Net Sales. Consolidated net sales were ~~$1,512.5~~$1,580.9 million for the three months ended ~~June~~September 30, 2008 compared to ~~$843.4~~$586.0 million for the three months ended ~~June~~September 30, 2007. The increase of ~~$669.1~~$994.9 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily due to an increase in petroleum net sales of ~~$650.1~~$964.4 million that resulted from higher product prices ($~~422.3~~203.1 million) and higher sales volumes ($~~227.8~~761.3 million) primarily resulting from the refinery turnaround which began in February 2007 and was completed in April ~~2007.~~2007 and refinery downtime resulting from the flood. In addition, nitrogen fertilizer net sales increased ~~$23.0~~$33.4 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 primarily due to higher plant gate prices ($~~13.3~~19.6 million) and an increase in overall sales volume ($~~9.7~~13.8 million). These results reflect, in part, refinery hardware expansions completed in 2007, particularly the CCR addition and coker expansion. The CCR produces significantly more hydrogen than the unit it replaces. As a result, our refinery purchases very little hydrogen from the fertilizer plant, allowing the fertilizer plant to use that hydrogen to produce ammonia.

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold (exclusive of depreciation and amortization) was ~~$1,287.5~~$1,440.3 million for the three months ended ~~June~~September 30, 2008 as compared to ~~$569.6~~$453.2 million for the three months ended ~~June,~~September, 2007. The increase of ~~$717.9~~$987.1 million for the

three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was attributable to an increase in crude throughput over the comparable period as the benefits of the refinery expansion positively impacted crude oil throughput, and the ~~refinery turnaround in April 2007~~downtime resulting from the flood had anthe impact of lowering refined fuel production volume in the quarter ended ~~June~~September 30, 2007. Additionally, higher crude oil prices were a significant contributor to the increase.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses (exclusive of depreciation and amortization) were ~~$62.3~~$56.6 million for the three months ended ~~June~~September 30, 2008 as compared to ~~$61.0~~$44.5 million for the three months ended ~~June~~September 30, 2007. This increase of ~~$1.3~~$12.1 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily due to an increase in ~~nitrogen fertilizer~~petroleum direct operating expenses of ~~$3.2~~$7.6 million primarily the result of increases in expenses associated with ~~property taxes, catalysts, outside services, repairs~~utilities and ~~maintenance, slag disposal~~energy, production chemicals, labor, insurance rent and ~~insurance~~operating materials partially offset by ~~decreases~~deceases in expenses associated with repairs and maintenance, taxes and outside services. Nitrogen fertilizer accounted for $4.5 million of the increase in direct operating expenses over the comparable period primarily as a result of increases in expenses associated with property taxes, outside services, utilities, catalyst, refractory, insurance, turnaround and slag disposal partially offset by deceases in expenses associated with repairs and maintenance, royalties and other ~~utilities, environmental and direct labor.~~expenses. The nitrogen fertilizer facility was subject to a property tax abatement that expired beginning in 2008. We have estimated our accrued property tax liability based upon the assessment value received by the county. This increase in nitrogen fertilizer expense was offset by a decrease in petroleum direct operating expenses of $1.8 million, primarily related to decreases in expenses associated with the refinery turnaround and outside services partially offset by increases in expenses associated with repairs and maintenance, utilities and energy, direct labor, environmental, production chemicals, property taxes and insurance.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses were ~~$14.8~~($7.8) million for the three months ended ~~June~~September 30, 2008 as compared to ~~$14.9~~$14.0 million for the three months ended ~~June~~September 30, 2007. This variance was primarily the result of decreases in ~~administrative labor ($11.1 million) primarily related to~~ share-based compensation ($26.3 million) and bank charges ($0.2 million) which ~~was~~were partially offset

by increases in expenses related to ~~the write-off of deferred CVR Partners, LP initial public offering costs~~administrative labor ($~~2.6~~1.5 million), outside services ($~~2.3 million), bad debt reserve ($3.5~~1.2 million), other selling, general and administrative costs ($~~1.0~~0.9 million), ~~asset write-off~~office costs ($~~0.9~~0.4 million) and insurance ($~~0.4~~0.3 million).

Net Costs Associated with Flood. Consolidated net costs associated with flood for the three months ended ~~June~~September 30, 2008 approximated ~~$3.9~~($0.8) million as compared to ~~$2.1~~$32.2 for the three months ended ~~June~~September 30, 2007. The $0.8 million of cost recoveries in net costs associated with flood for the three months ended September 30, 2008 resulted primarily from the collection of $15.0 million of insurance proceeds related to our environmental claim in excess of the environmental insurance receivable booked as recoverable for accounting purposes.

Depreciation and Amortization. Consolidated depreciation and amortization was ~~$21.1~~$20.6 million for the three months ended ~~June~~September 30, 2008 as compared to ~~$18.0~~$10.5 million for the three months ended ~~June~~September 30, 2007. The increase in depreciation and amortization for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of the completion of a significant capital project in the Petroleum business in February 2008.

Operating Income. Consolidated operating income was ~~$123.0~~$72.0 million for the three months ended ~~June~~September 30, 2008 as compared to operating income of ~~$177.8~~$31.6 million for the three months ended ~~June~~September 30, 2007. For the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007, petroleum operating income ~~decreased $64.4~~increased $0.8 million and nitrogen fertilizer operating income increased by ~~$11.4~~$32.7 million.

Interest Expense and Other Financing Costs. Consolidated interest expense for the three months ended ~~June~~September 30, 2008 was ~~$9.5~~$9.3 million as compared to interest expense of ~~$15.8~~$18.3 million for the three months ended ~~June~~September 30, 2007. This ~~$6.3~~$9.0 decrease for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 primarily resulted from an overall decrease in the index rates (primarily LIBOR) and a decrease in average borrowings outstanding during the comparable periods. Additionally, consolidated interest expense during the three months ended September 30, 2008 benefited from decreases in the applicable margins under our Credit Facility as compared to the applicable margins in effect for the three months ended September 30, 2007. See “— Liquidity and Capital Resources — Debt.”

Interest Income. Interest income was ~~$0.6~~$0.3 million for the three months ended ~~June~~September 30, 2008 as compared to $0.2 million for the three months ended ~~June~~September 30, 2007.

Swap. Realized losses on the Cash Flow Swap for the three months ended ~~June~~September 30, 2008 and the three months ended ~~June~~September 30, 2007 were ~~$52.4~~$33.8 million and ~~$88.7~~$45.4 million, respectively. The decrease in realized losses over the comparable periods was primarily the result of lower average crack spreads for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007. Unrealized losses represent the change in the mark-to-market value on the unrealized portion of the Cash Flow Swap based on changes in the forward NYMEX crack spread that is the basis for the Cash Flow Swap. In addition to the mark-to-market value of the Cash Flow Swap, the outstanding term of the Cash Flow Swap at the end of each period also affects the impact that the changes in the forward NYMEX crack spread may have on the unrealized gain or loss. As of ~~June~~September 30, 2008, the Cash Flow Swap had a remaining term of approximately ~~two years~~one year and nine months whereas as of ~~June~~September 30, 2007, the remaining term was approximately ~~three years.~~two years and nine months. As a result of the shorter remaining term as of ~~June~~September 30, 2008, a similar change in the forward NYMEX crack spread will have a smaller impact on the unrealized gain or loss. Unrealized ~~losses~~gains on our Cash Flow Swap for the three months ended ~~June~~September 30, 2008 and the three months ended ~~June~~September 30, 2007 were ~~$16.0~~$98.9 million and ~~$68.8~~$90.2 million, respectively.

Provision for Income Taxes. Income tax expense for the three months ended ~~June~~September 30, 2008 was ~~$4.1~~$40.4 million, or ~~12%~~28.9% of income before income taxes, as compared to ~~income tax benefit of $93.7~~$42.7 million, or 79.2%, for the three months ended ~~June~~September 30, 2007. The annualized effective rate for 2007, which was applied to loss before income

taxes for the three months ended ~~June~~September 30, 2007, is higher than the comparable annualized effective rate for 2008, primarily due to the correlation between the amount of credits which were projected to be generated in 2007 from the production of ultra low sulfur diesel fuel and the increased level of projected loss before income taxes for 2007. On an annualized basis, we expect to recognize net federal and state income tax expense at the statutory rate of approximately 39.9% on pre-tax earnings adjusted for permanent non-deductible or non-taxable items and to benefit from gross income tax credits of approximately ~~$59~~$60.4 million.

Minority Interest in (income) loss of Subsidiaries. Minority interest in loss of subsidiaries for the three months ended ~~June~~September 30, 2007 was ~~$0.4~~$0.1 million. Minority interest for 2007 related to common stock in two of our subsidiaries owned by our chief executive officer. In October 2007, in connection with our initial public offering, our chief executive officer exchanged his common stock in our subsidiaries for common stock of CVR.

Net Income (Loss). For the three months ended ~~June~~September 30, 2008, net income ~~decreased~~increased to ~~$31.0~~$99.7 million as compared to net income of ~~$100.1~~$11.2 million for the three months ended ~~June 30, 2007. The decrease of $69.1 million over the comparable periods was impacted by a significant income tax benefit recorded of $93.7 million for the three months ended June~~September 30, 2007.

Petroleum Results of Operations for the Three Months Ended ~~June~~September 30, 2008

Net Sales. Petroleum net sales were ~~$1,459.1~~$1,510.3 million for the three months ended ~~June~~September 30, 2008 compared to ~~$809.0~~$545.9 million for the three months ended ~~June~~September 30, 2007. The increase of ~~$650.1~~$964.4 million during the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of higher product prices ($~~422.3~~203.1 million) and higher sales volumes ($~~227.8~~761.3 million). Overall sales volumes of refined fuels for the three months ended ~~June~~September 30, 2008 increased ~~20%~~114% as compared to the three months ended ~~June~~September 30, 2007. The increased sales volume primarily resulted from a significant increase in refined fuel production volumes over the comparable ~~periods. In 2007, we invested in our~~period due to refinery ~~through significant capital expenditures that took place primarily~~downtime in the ~~first and second quarters of~~2007 period resulting from the ~~year. As a result of this planned expansion and turnaround, crude oil throughput was lower for the second quarter of 2007.~~flood. In the ~~second~~third quarter of 2007, crude oil throughput averaged ~~94,667~~52,497 barrels per day compared to ~~104,558~~114,678 barrels per day for the ~~second~~third quarter of 2008. In addition to the expansion that took place during 2007, we completed a significant capital project during the first quarter of 2008. The expansion allowed us to increase the level of daily throughput. Our average sales price per gallon for the three months ended ~~June~~September 30, 2008 for gasoline of ~~$3.12~~$3.06 and distillate of ~~$3.66~~$3.45 increased by ~~29%~~34% and ~~70%~~47%, respectively, as compared to the three months ended ~~June~~September 30, 2007.

~~ended June 30, 2008 compared to $570.6~~$1,437.7 million for the three months ended ~~June~~September 30, 2008 compared to $450.2 million for the three months ended September 30, 2007. The increase of ~~$715.0~~$987.5 million during the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was ~~partially~~primarily attributable to a ~~10%~~118% increase in crude oil throughput ~~over~~primarily due to refinery downtime in the comparable ~~periods as~~2007 period resulting from the ~~benefits of the refinery expansion program positively impacted crude throughput.~~flood. In addition to increased crude oil throughput, higher crude oil prices, increased sales volumes and the impact of FIFO accounting also impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil consumed for the three months ended ~~June~~September 30, 2008 was ~~$119.64~~$117.81 compared to ~~$59.69~~$70.93 for the comparable period of 2007, an increase of ~~100%~~66%. Sales volume of refined fuels increased ~~20%~~114% for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO ~~inventory gains~~impact when crude oil prices increase and an unfavorable FIFO ~~inventory losses~~impact when crude oil prices decrease. For the three months ended ~~June~~September 30, 2008, we had an unfavorable FIFO ~~inventory gains~~impact of ~~$74.0~~$59.3 million compared to a favorable FIFO ~~inventory gains~~impact of ~~$13.5~~$22.6 million for the comparable period of 2007.

Refining margin per barrel of crude throughput decreased from ~~$27.67~~$19.81 for the three months ended ~~June~~September 30, 2007 to ~~$18.23~~$6.88 for the three months ended ~~June~~September 30, 2008. Gross profit per barrel decreased to ~~$11.68~~$1.98 in the ~~first~~third quarter of 2008, as compared to ~~$20.73~~$6.42 per barrel in the equivalent period in 2007. The primary contributors to the negative variance in refining margin per barrel of crude throughput were ~~the 23% decrease ($4.98 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods and~~ unfavorable regional differences between gasoline and distillate prices in our primary marketing region and those of the NYMEX. The average gasoline basis for the three months ended ~~June~~September 30, 2008 decreased by ~~$9.06~~$6.16 per barrel to ~~a negative basis of ($3.61)~~$2.62 per barrel compared to ~~positive~~ basis of ~~$5.45~~$8.78 per barrel in the comparable period of 2007. The average distillate basis decreased by ~~$6.03~~$5.46 per barrel to ~~$4.17~~$4.68 per barrel compared to ~~$10.20~~$10.14 per barrel in the comparable period of 2007. FIFO inventory ~~gains~~losses of ~~$74.0~~$59.3 million for the three months ended ~~June~~September 30, 2008 as compared to FIFO inventory gains of ~~$13.5~~$22.6 million for the comparable

period of 2007 ~~partially offset~~also contributed significantly to the negative variance in refining margin per barrel of crude throughput over the comparable periods. Partially offsetting the negative effects of refined fuels basis and the impact of FIFO inventory changes was a 10% increase in the NYMEX 2-1-1 crack spread ~~and basis.~~($1.21 per barrel) over the comparable periods.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance (turnaround), labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were ~~$42.7~~$37.1 million for the three months ended ~~June~~September 30, 2008 compared to direct operating expenses of ~~$44.5~~$29.5 million for the three months ended ~~June~~September 30, 2007. The ~~decrease~~increase of ~~$1.8~~$7.6 million for the three months ended ~~June~~September 30, 2008 compared to the three months ended ~~June~~September 30, 2007 was the result of ~~decreases~~increases in expenses associated with ~~refinery turnaround~~utilities and energy ($~~10.7~~4.7 million), production chemicals ($2.8 million), labor ($1.7 million), insurance ($0.9 million), rent ($0.4 million) and ~~outside services~~operating materials ($~~0.7~~0.4 million). These ~~decreases~~increases in direct operating expenses were partially offset by ~~increases~~decreases in expenses associated with repairs and maintenance ($~~3.8~~2.5 million), ~~utilities and energy ($2.9 million), environmental ($0.8 million), direct labor ($0.6 million), production chemicals ($0.5 million), property~~ taxes ($~~0.4~~1.1 million) and ~~insurance~~outside services ($~~0.4~~0.8 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude oil throughput for the three months ended ~~June~~September 30, 2008 decreased to ~~$4.49~~$3.52 per barrel as compared to ~~$5.17~~$6.11 per barrel for the three months ended ~~June~~September 30, 2007.

Net Costs Associated with Flood. Petroleum net costs associated with flood for the three months ended ~~June~~September 30, 2008 recorded cost recoveries of approximated ~~$3.4~~$1.0 million as compared to ~~$2.0~~expense of approximately $28.6 million for the three months ended ~~June~~September 30, 2007. This cost recovery resulted primarily from the collection of $15.0 million of insurance proceeds related to our environmental claim in excess of the environmental insurance receivable booked as recoverable for accounting purposes.

Depreciation and Amortization. Petroleum depreciation and amortization was ~~$16.3~~$15.6 million for the three months ended ~~June~~September 30, 2008 as compared to ~~$13.3~~$6.6 million for the three months ended ~~June~~September 30, 2007. This increase in petroleum depreciation and amortization for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of a large capital project completed in February 2008.

Operating Income. Petroleum operating income was ~~$101.9~~$20.2 million for the three months ended ~~June~~September 30, 2008 as compared to operating income of ~~$166.3~~$19.4 million for the three months ended ~~June~~September 30, 2007. This ~~decrease~~increase of ~~$64.4~~$0.8 million from the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of a significant decrease in ~~the NYMEX 2-1-1 crack spread~~refined fuels basis and ~~basis~~a $81.9 million negative variance in FIFO inventory valuation over the comparable ~~periods, partially offset by FIFO inventory gains and a decrease of $1.8 million in direct operating expenses. Decreases~~periods. Additionally, increases in expenses associated with ~~refinery turnaround~~utilities and energy ($~~10.7~~4.7 million), production chemicals ($2.8 million), labor ($1.7 million), insurance ($0.9 million), rent ($0.4 million) and ~~outside services~~operating materials ($~~0.7~~0.4 million) also negatively impacted operating income over the comparable periods. These increases in direct operating expenses were partially offset by ~~increases~~decreases in expenses associated with repairs and maintenance ($~~3.8~~2.5 million), ~~utilities and energy~~

~~($2.9 million), environmental ($0.8 million), direct labor ($0.6 million), production chemicals ($0.5 million), property~~ taxes ($~~0.4~~1.1 million) and ~~insurance~~outside services ($~~0.4~~0.8 million).

Nitrogen Fertilizer Results of Operations for the Three Months Ended ~~June~~September 30, 2008

Net Sales. Nitrogen fertilizer net sales were ~~$58.8~~$74.2 million for the three months ended ~~June~~September 30, 2008 compared to ~~$35.8~~$40.8 million for the three months ended ~~June~~September 30, 2007. The increase of ~~$23.0~~$33.4 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was the result of higher plant gate prices ($~~13.3~~19.6 million), coupled with an increase in overall sales volumes ($~~9.7~~13.8 million) and a change in intercompany accounting for hydrogen from cost of product sold (exclusive of depreciation and amortization) to net sales ($2.6 million) over the comparable periods, which eliminates in consolidation..

In regard to product sales volumes for the three months ended ~~June~~September 30, 2008, our nitrogen fertilizer operations experienced ~~an increase~~a decrease of ~~43%~~11% in ammonia sales unit volumes ~~(5,752~~(2,719 tons) and an increase of 9%37% in UAN sales unit volumes ~~(11,829~~(44,755 tons). On-stream factors (total number of hours operated divided by total hours in the reporting period) for ~~the~~all units gasification, ammonia and ~~ammonia units~~UAN plant were ~~less~~significantly greater than on-stream factors for the comparable period. ~~On-stream factors for the UAN plant were greater than the three month period ended June 30, 2007.~~ During the three months ended ~~June~~September 30, ~~2008, the gasification, ammonia and UAN~~2007, all three primary nitrogen fertilizer units experienced ~~approximately sixteen,~~ eighteen ~~and twenty~~ days of downtime associated with ~~various repairs, respectively. Our second quarter production in 2008 was below our expectations due to catalyst changeout and~~the flood. In addition, the UAN plant also experienced unscheduled downtime ~~at our main~~for repairs and ~~spare gasifiers in late May and early June 2008.~~maintenance. 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 ~~June~~September 30, 2008 for ammonia and UAN were greater than plant gate prices for the comparable period of 2007 by ~~44%~~89% and ~~39%~~38%, respectively. This dramatic increase in nitrogen fertilizer prices was not the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to the historically low ending stocks of global grains and a surge in prices for corn, wheat and soybeans, the primary crops in our region. This increase in demand for nitrogen-based fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation to natural gas prices.

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

Cost of Product Sold Exclusive of Depreciation and Amortization.Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold (excluding depreciation and amortization) for the three months ended ~~June~~September 30, 2008 was ~~$6.8~~$6.2 million compared to ~~$0.1~~$3.7 million for the three months ended ~~June~~September 30, 2007. The increase of ~~$6.7~~$2.5 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of a change in intercompany accounting for hydrogen reimbursement. For the three months ended ~~June~~September 30, 2007, hydrogen reimbursement was included in cost of product sold (exclusive of depreciation and amortization). For the three months ended ~~June~~September 30, 2008, hydrogen has been included in net sales. These amounts eliminate in consolidation. Hydrogen is transferred from our nitrogen fertilizer operations to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit. This transfer of hydrogen has virtually been eliminated with the completion and operation of the CCR at the refinery.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our nitrogen fertilizer operations include costs associated with the actual operations of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct operating expenses (exclusive of depreciation and amortization)

for the three months ended ~~June~~September 30, 2008 were ~~$19.7~~$19.4 million as compared to ~~$16.5~~$14.9 million for the three months ended ~~June~~September 30, 2007. The increase of ~~$3.2~~$4.5 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of increases in expenses associated with property taxes ($2.5 million), ~~catalysts~~outside services ($~~1.0~~1.3 million), ~~outside services~~utilities ($0.9 million), catalyst ($0.7 million), ~~repairs and maintenance~~refractory ($0.3 million), insurance ($0.2 million), ~~slag disposal~~turnaround ($~~0.2~~0.1 million) and ~~insurance~~slag disposal ($0.1 million). These increases in direct operating expenses were partially offset by decreases in expenses associated with repairs and maintenance ($1.1 million) and royalties and other ($~~0.9 million), utilities ($0.4 million), environmental ($0.2 million) and direct labor ($0.1~~0.8 million).

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased to $4.5 million for the three months ended ~~June~~September 30, 2008 as compared to ~~$4.4~~$3.6 million for the three months ended ~~June~~September 30, 2007.

Net Costs Associated with Flood. Nitrogen ~~fertilizer depreciation and amortization increased by approximately $0.1 million~~net costs associated with flood for the three months ended ~~June~~September 30, ~~2008 compared to~~2007 was approximately $1.9 million. There were no costs associated with the flood for the three months ended ~~June~~September 30, ~~2007.~~2008.

Operating Income. Nitrogen fertilizer operating income was ~~$23.1~~$46.5 million for the three months ended ~~June~~September 30, 2008 as compared to operating income of ~~$11.7~~$13.8 million for the three months ended ~~June~~September 30, 2007. This increase of ~~$11.4~~$32.7 million for the three months ended ~~June~~September 30, 2008 as compared to the three months ended ~~June~~September 30, 2007 was primarily the result of increased fertilizer prices and sales volumes over the

comparable periods. Mitigating the increased fertilizer prices and sales volumes over the comparable periods were increases in direct operating expenses associated with property taxes ($2.5 million), ~~catalysts~~outside services ($~~1.0~~1.3 million), ~~outside services~~utilities ($0.9 million), catalyst ($0.7 million), ~~repairs and maintenance~~refractory ($0.3 million), insurance ($0.2 million), ~~slag disposal~~turnaround ($~~0.2~~0.1 million) and ~~insurance~~slag disposal ($0.1 million). These increases in direct operating expenses were partially offset by decreases in expenses associated with repairs and maintenance ($1.1 million) and royalties and other ($~~0.9 million), utilities ($0.4 million), environmental ($0.2 million) and direct labor ($0.1~~0.8 million).

~~Six~~Nine Months Ended ~~June~~September 30, 2008 Compared to the ~~Six~~Nine Months Ended ~~June~~September 30, 2007

Consolidated Results of Operations

Net Sales. Consolidated net sales were ~~$2,735.5~~$4,316.4 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to ~~$1,233.9~~$1,819.9 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$1,501.6~~$2,496.5 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily due to an increase in petroleum net sales of ~~$1,466.2~~$2,430.6 million that resulted from higher sales volumes ($~~874.7~~1,623.1 million), coupled with higher product prices ($~~591.5~~807.5 million). In addition, nitrogen fertilizer net sales increased ~~$47.1~~$80.5 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 due to higher sales volumes ($~~13.7~~19.3 million), ~~together with~~ higher plant gate prices ($~~33.4~~53.3 million). and a change in intercompany accounting for hydrogen from cost of product sold (exclusive of depreciation and amortization) to net sales ($7.9 million) over the comparable periods, which eliminates in consolidation.

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold (exclusive of depreciation and amortization) was ~~$2,323.7~~$3,764.0 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$873.3~~$1,326.6 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$1,450.4~~$2,437.4 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily due to the refinery turnaround that began in February 2007 and was completed in April ~~2007.~~2007 and refinery downtime resulting from the flood. In addition to the impact of the turnaround and the flood, higher crude oil prices, increased sales volumes and the impact of FIFO accounting impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$105.87,~~$110.10, compared to ~~$57.14~~$60.90 for the comparable period of 2007, an increase of ~~85%~~81%. Sales volume of refined fuels increased ~~54%~~70% for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 principally due to the ~~turnaround.~~turnaround and refinery downtime resulting from the flood.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses (exclusive of depreciation and amortization) were ~~$122.9~~$179.5 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$174.4~~$218.8 million for the ~~six~~nine months ended ~~June~~September 30, 2007. This decrease of ~~$51.5~~$39.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was due to a decrease in petroleum direct operating expenses of ~~$58.1~~$50.6 million, primarily related to the refinery turnaround, ~~and~~partially offset by an increase in nitrogen fertilizer direct operating expenses of ~~$6.7~~$11.3 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses were ~~$28.3~~$20.5 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$28.1~~$42.1 million for the ~~six~~nine months ended ~~June~~September 30, 2007. This variance was primarily the result of

decreases in share-based compensation ($41.3 million) which was partially offset by increases in expenses associated with outside services ($~~4.6~~5.8 million), bad debt reserve ($3.9 million), the write-off of deferred CVR Partners, LP initial public offering costs ($~~2.6~~2.5 million), administrative labor ($2.3 million), other selling, general, and administrative ~~costs~~expenses ($~~1.1~~2.0 million), asset write-off ($~~1.0~~0.9 million), insurance ($0.9 million) and ~~insurance~~office costs ($~~0.7~~0.6 million) ~~partially offset by a reduction in expenses associated with administrative labor ($14.1 million) primarily related to share-based compensation.~~.

Net Costs Associated with Flood. Consolidated net costs associated with the flood for the ~~six~~nine months ended ~~June~~September 30, 2008 approximated ~~$9.7~~$8.8 million as compared to ~~$2.1~~$34.3 for the ~~six~~nine months ended ~~June~~September 30, 2007.

Depreciation and Amortization. Consolidated depreciation and amortization was ~~$40.7~~$61.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$32.2~~$42.7 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$8.5~~$18.6 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~

September 30, 2007 was primarily the result of the expansion completed in April 2007 and a significant capital project completed in February 2008 in the petroleum business.

Operating Income. Consolidated operating income was ~~$210.3~~$282.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to operating income of ~~$123.8~~$155.4 million for the ~~six~~nine months ended ~~June~~September 30, 2007. For the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007, petroleum operating income increased by ~~$62.6~~$63.4 million and nitrogen fertilizer operating income increased by ~~$28.2~~$60.7 million.

Interest Expense. Consolidated interest expense for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$20.8~~$30.1 million as compared to interest expense of ~~$27.6~~$46.0 million for the ~~six~~nine months ended ~~June~~September 30, 2007. This ~~25%~~35% decrease for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 primarily resulted from an overall decrease in the index rates (primarily LIBOR) and a decrease in average borrowings outstanding during the ~~six~~nine months ended ~~June~~September 30, 2008. Additionally, consolidated interest expense during the nine months ended September 30, 2008 benefited from decreases in the applicable margins under our Credit Facility dated December 28, 2006 as compared to the applicable margin in effect during the nine months ended September 30, 2007. See “— Liquidity and Capital Resources — Debt.” Partially offsetting these positive impacts on consolidated interest expense was a ~~$5.1~~$7.7 million decrease in capitalized interest over the comparable period due to the decrease of capital projects in progress during the ~~six~~nine months ended ~~June~~September 30, 2008. Additionally, consolidated interest expense during the six months ended June 30, 2008 benefited from decreases in the applicable margins under our Credit Facility dated December 28, 2006 as compared to our borrowing facility completed in association with the Subsequent Acquisition that was in effect during the six months ended June 30, 2007. See “— Liquidity and Capital Resources — Debt.”

Interest Income. Interest income was ~~$1.3~~$1.6 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$0.6~~$0.8 million for the ~~six~~nine months ended ~~June~~September 30, 2007.

~~Loss~~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 ~~six~~nine months ended ~~June~~September 30, 2008, we incurred a ~~$127.2~~$50.5 million net loss on derivatives as compared to a ~~$292.4~~$251.9 million loss on derivatives for the ~~six~~nine months ended ~~June~~September 30, 2007. This significant decrease in loss on derivatives, net for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily attributable to the realized and unrealized losses on our Cash Flow Swap. Realized losses on the Cash Flow Swap for the ~~six~~nine months ended ~~June~~September 30, 2008 and the ~~six~~nine months ended ~~June~~September 30, 2007 were ~~$74.0~~$107.7 million and ~~$97.2~~$142.6 million, respectively. The decrease in realized losses over the comparable periods was primarily the result of lower average crack spreads for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007. Unrealized gains or losses represent the change in the mark-to-market value on the unrealized portion of the Cash Flow Swap based on changes in the forward NYMEX crack spread that is the basis for the Cash Flow Swap. In addition to the mark-to-market value of the Cash Flow Swap, the outstanding term of the Cash Flow Swap at the end of each period also affects the impact that the changes in the forward NYMEX crack spread may have on the unrealized gain or loss. As of ~~June~~September 30, 2008, the Cash Flow Swap had a remaining term of approximately ~~two years~~one year and nine months whereas as of ~~June~~September 30, 2007, the remaining term on the Cash Flow Swap was approximately ~~three years.~~two years and nine months. As a result of those shorter remaining term as of June 30, 2008, a similar change in the forward NYMEX crack spread will have a smaller impact on the unrealized gain or loss. Unrealized ~~losses~~gains on our Cash Flow Swap for the ~~six~~nine months ended ~~June~~September 30, 2008 ~~and~~were $69.1 million. In contrast, the ~~six~~unrealized losses on the Cash Flow Swap for the nine months ended ~~June~~September 30, 2007 were ~~$29.9 million and $188.5 million, respectively.~~$98.3 million.

Provision for Income Taxes. Income tax expense for the ~~six~~nine months ended ~~June~~September 30, 2008 was approximately ~~$10.9~~$51.3 million, or ~~17%~~25.1% of earnings before income taxes, as compared to income tax benefit of approximately ~~$141.0~~$98.2 million, or 69.3%, for the ~~six~~nine months ended ~~June~~September 30, 2007. The annualized effective tax rate for 2008, which was

applied to earnings before income taxes for the ~~six~~nine month period ended ~~June~~September 30, 2008, is lower than the comparable annualized effective tax rate for 2007, which was applied to loss before income taxes for the ~~six~~nine month period ended ~~June~~September 30, 2007, primarily due to the correlation between the amount of income tax credits which were projected to be generated in 2007 in comparison with the projected pre-tax loss for 2007.

Minority Interest in (income) loss of Subsidiaries. Minority interest in ~~(income) loss~~income of subsidiaries for the ~~six~~nine months ended ~~June~~September 30, 2007 was $0.2 million. Minority interest in the 2007 period related to common stock in two of our subsidiaries owned by our chief executive officer.

Net Income (Loss). For the ~~six~~nine months ended ~~June~~September 30, 2008, net income was ~~$53.2~~$152.9 million as compared to a net loss of ~~$54.3~~$43.1 million for the ~~six~~nine months ended ~~June~~September 30, 2007.

Petroleum Results of Operations for the ~~Six~~Nine Months Ended ~~June~~September 30, 2008

Net Sales. Petroleum net sales were ~~$2,627.6~~$4,137.9 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to ~~$1,161.4~~$1,707.3 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$1,466.2~~$2,430.6 million from the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of significantly higher sales volumes ($~~874.7~~1,623.1 million) and increased product prices ($~~591.5~~807.5 million). Overall sales volumes of refined fuels for the ~~six~~nine months ended ~~June~~September 30, 2008 increased ~~54%~~70% as compared to the ~~six~~nine months ended ~~June~~September 30, 2007. The increased sales volume resulted primary from a significant decrease in refined fuel production volumes over the ~~six~~nine months ended ~~June~~September 30, 2007 due to the refinery turnaround which began in February 2007 and was completed in April ~~2007.~~2007 and refinery downtime resulting from the flood. Our average sales price per gallon for the ~~six~~nine months ended ~~June~~September 30, 2008 for gasoline of ~~$2.77~~$2.87 and distillate of ~~$3.26~~$3.33 increased by ~~33%~~34% and ~~61%~~57%, respectively, as compared to the ~~six~~nine months ended ~~June~~September 30, 2007.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was ~~$2,320.6~~$3,758.4 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to ~~$869.1~~$1,319.2 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$1,451.5~~$2,439.2 million from the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of a significant increase in crude throughput due to the refinery turnaround which began in February 2007 and was completed in April ~~2007.~~2007 and refinery downtime resulting from the flood. In addition to the impact of the turnaround, higher crude oil prices, increased sales volumes and the impact of FIFO accounting impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$105.87,~~$110.10, compared to ~~$57.14~~$60.90 for the comparable period of 2007, an increase of ~~85%~~81%. Sales volume of refined fuels increased ~~54%~~70% for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 principally due to the ~~turnaround.~~turnaround and the downtime resulting from the flood. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease. For the ~~six~~nine months ended ~~June~~September 30, 2008, we reported a favorable FIFO ~~inventory gains~~impact of ~~$100.1~~$25.9 million compared to a favorable FIFO ~~inventory gains~~impact of ~~$12.9~~$36.9 million for the comparable period of 2007.

Refining margin per barrel of crude throughput decreased to ~~$15.98~~$12.75 for the ~~six~~nine months ended ~~June~~September 30, 2008 from ~~$22.71~~$21.93 for the ~~six~~nine months ended ~~June~~September 30, 2007 primarily due to the ~~15% decrease ($2.65 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods and~~ unfavorable regional differences between gasoline and distillate prices in our primary marketing region (the Coffeyville supply area) and those of the NYMEX. The average gasoline basis for the ~~six~~nine months ended ~~June~~September 30, 2008 decreased by ~~$5.15~~$5.49 per barrel to a negative basis of ~~$2.56~~($0.81) per barrel compared to ~~$2.59~~$4.68 per barrel in the comparable period of 2007. The average distillate basis for the ~~six~~nine months ended ~~June~~September 30, 2008 decreased by ~~$5.63~~$5.60 per barrel to ~~$3.91~~$4.17 per barrel compared to ~~$9.54~~$9.77 per barrel in the comparable period of 2007. Also contributing to the reduced refining margin per barrel was the 9% decrease ($1.36 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance (turnaround), labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were ~~$83.0~~$120.1 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to direct operating expenses of ~~$141.1~~$170.7 million for the ~~six~~nine months ended

~~June~~ September 30, 2007. The decrease of ~~$58.1~~$50.6 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was the result of decreases in expenses associated with the refinery turnaround ($~~76.9~~76.8 million), and outside services ($~~1.1 million) and direct labor ($1.0~~1.8 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ($~~7.2~~11.9 million), production chemicals ($5.3 million), repairs and maintenance ($~~7.1 million), production chemicals ($2.5 million), environmental compliance ($1.3 million), property taxes ($1.2~~4.6 million), insurance ($~~0.8~~1.7 million),

environmental compliance ($1.4 million), direct labor ($0.7 million), rent and lease ($~~0.2~~0.5 million), operating materials ($0.5 million) and ~~operating materials~~property taxes ($0.1 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude throughput for the ~~six~~nine months ended ~~June~~September 30, 2008 decreased to ~~$4.32~~$4.04 per barrel as compared to ~~$10.96~~$9.64 per barrel for the ~~six~~nine months ended ~~June~~September 30, 2007 principally due to refinery turnaround expenses and the related downtime associated with the turnaround and its impact on overall production ~~volume.~~volume and downtime resulting from the flood.

Net Costs Associated with Flood. Petroleum net costs associated with the flood for the ~~six~~nine months ended ~~June~~September 30, 2008 approximated ~~$8.9~~$7.9 million as compared to ~~$2.0~~$30.6 million for the ~~six~~nine months ended ~~June~~September 30, 2007.

Depreciation and Amortization. Petroleum depreciation and amortization was ~~$31.2~~$46.8 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$23.1~~$29.7 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$8.1~~$17.1 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of the completion of the expansion in April 2007 and a significant capital project completed in February 2008.

Operating Income. Petroleum operating income was ~~$165.5~~$185.7 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to operating income of ~~$102.9~~$122.3 million for the ~~six~~nine months ended ~~June~~September 30, 2007. This increase of ~~$62.6~~$63.4 million from the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of the refinery turnaround which began in February 2007 and was completed in April ~~2007.~~2007 and refinery downtime resulting from the flood. The turnaround and the flood negatively impacted daily refinery crude throughput and refined fuels production. In addition, direct operating expenses decreased substantially during the ~~six~~nine months ended ~~June~~September 30, 2008 primarily due to decreases in expenses associated with the refinery turnaround ($~~76.9~~76.8 million), and outside services ($~~1.1 million) and direct labor ($1.0~~1.8 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ($~~7.2~~11.9 million), production chemicals ($5.3 million), repairs and maintenance ($~~7.1~~4.6 million), ~~production chemicals~~insurance ($~~2.5~~1.7 million), environmental compliance ($~~1.3~~1.4 million), ~~property taxes~~direct labor ($~~1.2 million), insurance ($0.8~~0.7 million), rent and lease ($~~0.2~~0.5 million), operating materials ($0.5 million) and ~~operating materials~~property taxes ($0.1 million).

Nitrogen Fertilizer Results of Operations for the ~~Six~~Nine Months Ended ~~June~~September 30, 2008

Net Sales. Nitrogen fertilizer net sales were ~~$121.4~~$195.6 million for the ~~six~~nine months ended ~~June~~September 30, 2008 compared to ~~$74.3~~$115.1 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$47.1~~$80.5 million from the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was the result of higher plant gate prices ($~~33.4~~53.3 million), coupled with an increase in overall sales volumes ($~~13.7~~19.3 million). and a change in intercompany accounting for hydrogen from cost of product sold (exclusive of depreciation and amortization) to net sales ($7.9 million) over the comparable periods, which eliminates in consolidation.

In regard to product sales volumes for the ~~six~~nine months ended ~~June~~September 30, 2008, our nitrogen operations experienced an increase of ~~27%~~11% in ammonia sales unit volumes ~~(9,175~~(6,456 tons) and an increase of 1%12% in UAN sales unit volumes ~~(3,068~~(47,824 tons). On-stream factors (total number of hours operated divided by total hours in the reporting period) for ~~the~~all units, gasification, ammonia and ~~ammonia units~~UAN plant were ~~less~~greater than the comparable period, primarily due to unscheduled ~~downtime. On-stream factors for~~downtime and nitrogen plant downtime resulting from the ~~UAN plant were slightly improved for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007.~~flood. It is typical to experience brief outages in complex manufacturing operations such as our nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.

Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both FOB our plant gate (sold plant) and FOB the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or six months to six months. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the ~~six~~nine months ended ~~June~~September 30, 2008 for ammonia were greater than plant gate prices for the comparable period of 2007 by ~~44%~~59%. Similarly, UAN plant gate prices for the ~~six~~nine months ending ~~June~~September 30, 2008 were greater than the comparable period of 2007 by ~~48%~~46%. This dramatic increase in nitrogen fertilizer prices was not the direct result of an increase in natural gas prices, but rather the result of

increased demand for nitrogen-based fertilizers due to the historically low ending stocks of global grains and a

surge in prices for corn, wheat and soybeans, the primary crops in our region. This increase in demand for nitrogen-based fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation to natural gas prices.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense, freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$15.8~~$21.9 million compared to ~~$6.2~~$9.9 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$9.6~~$12.0 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of a change in intercompany accounting for hydrogen ~~reimbursement.~~reimbursement ($10.6 million) and a $3.1 million increase in freight expense over the comparable periods. For the ~~six~~nine months ended ~~June~~September 30, 2007, hydrogen reimbursement was included in cost of product sold (exclusive of depreciation and amortization). For the ~~six~~nine months ended ~~June~~September 30, 2008, hydrogen has been included in net sales. These amounts eliminate in consolidation. Hydrogen is transferred from our nitrogen fertilizer operations to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit. This transfer of hydrogen has virtually been eliminated with the completion and operation of the CCR at the refinery.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Nitrogen fertilizer operations include costs associated with the actual operations of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct operating expenses (exclusive of depreciation and amortization) for the ~~six~~nine months ended ~~June~~September 30, 2008 were ~~$39.9~~$59.4 million as compared to ~~$33.2~~$48.1 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The increase of ~~$6.7~~$11.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was primarily the result of increases in expenses associated with property taxes ($~~4.9~~7.4 million), outside services ($2.2 million), catalyst ($2.0 million), repairs and maintenance ($~~1.8 million), catalysts ($1.2 million), outside services ($0.9~~0.7 million), slag disposal ($0.4 million), refractory ($0.3 million), insurance ($0.3 million) and direct labor ($~~0.2 million) and insurance ($0.1~~0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with royalties and other ($~~1.4~~2.3 million), environmental compliance ($~~0.3~~0.2 million), equipment rental ($0.1 million) and ~~equipment rental~~utilities ($~~0.2~~0.1 million).

Net Costs Associated with Flood. ~~Nitrogen~~The nitrogen fertilizer operations did not record any costs associated with the flood for the ~~six~~nine months ended ~~June~~September 30, 2008 ~~approximated $0 million~~ as compared to ~~$0.1~~$2.0 million for the ~~six~~nine months ended ~~June~~September 30, 2007.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased to ~~$9.0~~$13.4 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$8.8~~$12.4 million for the ~~six~~nine months ended ~~June~~September 30, 2007.

Operating Income. Nitrogen fertilizer operating income was ~~$49.2~~$95.6 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to ~~$21.0~~$34.9 million for the ~~six~~nine months ended ~~June~~September 30, 2007. This increase of ~~$28.2~~$60.7 million for the ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the ~~six~~nine months ended ~~June~~September 30, 2007 was the result of increased sales volumes ($~~13.7~~27.2 million), coupled with higher plant gate prices for both UAN and ammonia ($~~33.4~~53.3 million). Partially offsetting the positive effects of sales volumes and higher plant gate prices were increased direct operating expenses primarily the result of increases in expenses associated with property taxes ($~~4.9~~7.4 million), outside services ($2.2 million), catalyst ($2.0 million), repairs and maintenance ($~~1.8~~0.7 million), ~~catalysts ($1.2 million), outside services ($0.9 million)~~ slag disposal ($0.4 million), refractory ($0.3 ~~million,~~million), insurance ($0.3 million) and direct labor ($~~0.2 million) and insurance ($0.1~~0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with royalties and other ($~~1.4~~2.3 million), environmental compliance ($~~0.3~~0.2 million), equipment rental ($0.1 million) and ~~equipment rental~~utilities ($~~0.2~~0.1 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 and third party guarantees of obligations under the Cash Flow Swap. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily

dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses.

As of ~~June~~September 30, 2008, total outstanding debt under our credit facility was ~~$508.3 million, which includes $21.5 million from~~$485.5 million. There was no balance outstanding under our revolving credit facility. As of ~~August 11,~~November 6, 2008, total outstanding debt under our credit facility was ~~$485.5~~$484.3 million, which was all term debt. As of ~~June~~September 30, 2008, we had cash, cash equivalents and short-term investments of ~~$20.6~~$59.9 million and up to ~~$91.1~~$115.1 million available under our revolving credit facility. As of ~~August 11,~~November 6, 2008, we had cash, cash equivalents and short-term investments of ~~$44.5~~$54.3 million and up to ~~$112.6~~$115.1 million available under our revolving credit facility. In the current crude oil price environment, working capital is subject to substantial variability from week-to-week and month-to-month. The payable to swap counterparty included in the consolidated balance sheet at ~~June~~September 30, 2008 was approximately ~~$418.3~~$264.5 million, and the current portion included ~~an increase~~a decrease of ~~$109.2~~$25.8 million from December 31, 2007, resulting in an equal ~~reduction~~increase in our working capital for the same period.

On June 30, 2007, our refinery and the nitrogen fertilizer plant were severely flooded and forced to conduct emergency shutdowns and evacuate. See Note 9,10, “Flood, Crude Oil Discharge and Insurance Related Matters.” Our liquidity was significantly negatively impacted as a result of the reduction in cash provided by operations due to our temporary cessation of operations and the additional expenditures associated with the flood and crude oil discharge. In order to provide immediate and future liquidity, on August 23, 2007 we deferred payments of $123.7 million which were due to J. Aron under the terms of the Cash Flow Swap. We entered into a letter agreement with J. Aron on July 29, 2008 to defer to December 15, 2008 the payment of $87.5 million of the $123.7 million plus accrued ~~interest ($6.7~~interest. On August 29, 2008 we paid $36.2 of the remaining balance to J. Aron, as well as $7.1 million asin accrued interest.

Subsequent to the quarter end, we paid an additional $15.0 million through use of ~~August 1, 2008) we owe.~~proceeds received on the environmental insurance policy. The ~~remaining $36.2~~deferral agreement with J. Aron was further amended on October 11, 2008 and the outstanding balance of $72.5 million ~~plus accrued interest will be due~~ on ~~August 31, 2008 (or earlier at the company’s option). If we consummate our proposed convertible debt offering before December 15, 2008, the $87.5 million deferral will automatically extend~~that date was further deferred to July 31, 2009. ~~See “— Payment Deferrals Related~~Additional proceeds of $9.8 million received under the property insurance policy subsequent to ~~Cash Flow Swap” for additional information about~~October 11, 2008 were used to pay down the ~~payment deferral. These deferrals are supported by third-party guarantees.~~ principle balance on the deferral amount to $62.7 million as of November 6, 2008.

We paid J. Aron ~~$52.4~~$33.8 million on ~~July 8,~~October 7, 2008 for ~~crude oil we settled~~settlement of our realized losses with respect to the Cash Flow Swap for the quarter ~~ending June~~ended September 30, 2008.

The crude oil intermediation agreement with J. Aron expires on December 31, 2008. We are currently negotiating with multiple parties to enter into a new intermediation agreement to replace the J. Aron agreement. There can be no assurance that we will be able to enter into a new agreement on favorable terms, on a timely basis, or at all.

Our liquidity is significantly effected by the market price of crude oil. Higher crude oil prices hurt our liquidity and lower crude oil prices enhance our liquidity. Given the reduction in crude oil prices in the third quarter of 2008 and thereafter, we elected to withdraw our convertible notes offering registration statement from the SEC as we concluded that such offering was no longer necessary.

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

Credit Facility

extended beyond the final maturity of the term loans, which is December 28, 2013. As of ~~June~~September 30, 2008, we had available ~~$91.1~~$115.1 million under the revolving credit facility.

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

The Credit Facility incorporates the following pricing by facility type:


	•	Tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions).

	•	Revolving loan borrowings bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions).

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

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

In addition to the fees stated above, the Credit Facility requires the borrower to pay 0.50% per annum in commitment fees on the unused portion of the revolving loan facility.

The Credit Facility requires the borrower to prepay outstanding loans, subject to certain exceptions, with:


	•	100% of the net asset sale proceeds received from specified asset sales and net insurance/condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to


		reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations;


	•	100% of the cash proceeds from the incurrence of specified debt obligations; and

	•	75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 or 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00.

Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving letters of credit and funded letters of credit. Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.

The Credit Facility contains customary covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of ~~Coffeyville Resources, LLC~~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 ~~Coffeyville Resources, LLC~~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 borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap or the Partnership’s partnership agreement without the prior written approval of the lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.

The Credit Facility also requires the borrower to maintain certain financial ratios as follows:


	Minimum
	Interest		Maximum
	Coverage		Leverage
Fiscal Quarter Ending	Ratio		Ratio

~~June 30, 2008~~		~~3.25:1.00~~	~~3.00:1.00~~
September 30, 2008		3.25:1.00	2.75:1.00
December 31, 2008		3.25:1.00	2.50:1.00
March 31, 2009 and thereafter		3.75:1.00	2.25:1.00
			to December 31, 2009, 2.00:1.00 thereafter

The computation of these ratios is governed by the specific terms of the Credit Facility and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general, under the terms of our Credit Facility, consolidated adjusted EBITDA is calculated by adding consolidated net income, consolidated interest expense, income taxes, depreciation and amortization, other non- cash expenses, any fees and expenses related to permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests and major scheduled turnaround expenses. As of ~~June~~September 30, 2008, we were in compliance with our covenants under the Credit Facility.

We present consolidated adjusted EBITDA because it is a material component of material covenants within our current Credit Facility and significantly impacts our liquidity and ability to borrow under our revolving line of

credit. However, consolidated adjusted EBITDA is not a defined term under GAAP and should not be considered as

an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the Credit Facility as follows:


	Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
	2008			2007			2008			2007			2008			2007			2008			2007
	(Unaudited in millions)						(Unaudited in millions)						(Unaudited in millions)						(Unaudited in millions)

Consolidated Financial Results
Net income (loss)	$	31.0		$	100.1		$	53.2		$	(54.3	)	$	99.7		$	11.2		$	152.9		$	(43.1	)
Plus:
Depreciation and amortization		21.1			18.0			40.7			32.2			20.6			18.1			61.3			50.3
Interest expense and other financing costs		9.5			15.8			20.8			27.6			9.3			18.3			30.1			46.0
Income tax expense (benefit)		4.1			(93.7	)		10.9			(141.0	)		40.4			42.7			51.3			(98.2	)
Funded letters of credit expense and interest rate swap not included in interest expense		2.4			0.2			3.3			0.2			2.3			0.7			5.6			0.9
Major scheduled turnaround expense		—			10.8			—			76.8			0.1			—			0.1			76.8
Unrealized loss on derivatives		12.9			63.1			31.8			190.0
Unrealized gain (loss) on derivatives														(100.6	)		(86.2	)		(68.8	)		103.8
Non-cash compensation expense for equity awards		(10.8	)		3.0			(11.2	)		6.8			(25.6	)		4.5			(36.8	)		11.3
Loss on disposition of fixed assets		1.5			1.1			1.6			1.2						0.1			1.6			1.2
Minority interest		—			0.4			—			(0.3	)		—			0.1			—			(0.2	)
Management fees		—			0.5			—			1.1			—			0.5			—			1.6
Unusual or non recurring charges														—			—			3.2			—
Property tax — increase due to expiration of abatement														7.4			—			7.4			—

Adjusted EBITDA	$	71.7		$	119.3		$	151.1		$	140.3		$	53.6		$	10.0		$	207.9		$	150.4

In addition to the financial covenants summarized in the table above, the Credit Facility restricts the capital expenditures of ~~Coffeyville Resources, LLC~~CRLLC to $125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and $50.0 million in 2011 and thereafter. The capital expenditures covenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ended December 31, 2008. We believe the limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our Credit Facility.

The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20.0 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20.0 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20.0 million, events relating to employee benefit plans resulting in liability in excess of $20.0 million, a change in control, the guarantees, collateral documents or the Credit Facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the Credit Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.

Qualified IPO, (1) we ~~will be~~are allowed to borrow an additional $225.0 million under the Credit Facility ~~after June 30, 2008~~ to finance capital enhancement projects if we are in pro forma compliance with the financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we ~~will be~~are allowed to pay an additional $35.0 million of dividends each year, if our corporate family ratings are at least B2 from Moody’s and B from S&P, (3) we will not be subject to any capital expenditures limitations commencing with fiscal 2009 if our total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter ended December 31, 2008, and (4) ~~at any time after March 31, 2008~~ we ~~will be~~are allowed to reduce the Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or equal to 1.25:1 and we have a corporate family rating of at least B2 from Moody’s and B from S&P.

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

At ~~June~~September 30, 2008 and December 31, 2007, funded long-term debt, including current maturities, totaled ~~$486.8~~$485.5 million and $489.2 million, respectively, of tranche D term loans. Other commitments at ~~June~~September 30, 2008 and December 31, 2007 included a $150.0 million funded letter of credit facility and a $150.0 million revolving credit facility. As of ~~June~~September 30, 2008, the commitment outstanding on the revolving credit facility was ~~$58.9~~$34.9 million, including ~~$21.5 million in~~no revolver borrowings, ~~$5.8~~$3.3 million in letters of credit in support of certain environmental obligations and $31.6 million in letters of credit to secure transportation services for crude oil. As of December 31, 2007, the commitment outstanding on the revolving credit facility was $39.4 million, including $5.8 million in letters of credit in support of certain environmental obligations, $3.0 million in support of surety bonds in place to support state and federal excise tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for crude oil.

Payment Deferrals Related to Cash Flow Swap

As a result of the flood and the temporary cessation of our operations on June 30, 2007, ~~Coffeyville Resources, LLC~~CRLLC entered into several deferral agreements with J. Aron with respect to the Cash Flow ~~Swap.~~Swap, which is a series of commodity derivative arrangements whereby if crack spreads fall below a fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above a fixed level, we agreed to pay the difference to J. Aron. These deferral agreements deferred to ~~January~~August 31, 2008 the payment of approximately $123.7 million ~~(plus~~plus accrued interest. On July 29, 2008, CRLLC entered into a revised letter agreement with the J. Aron to defer further $87.5 million of the deferred payment amounts under the 2007 deferral agreements to December 15, 2008. On August 29, 2008, in accordance with the additional deferral agreement, we paid $36.2 million to J. Aron, as well as $7.1 million in accrued interest as of ~~$6.2~~that date resulting in a remaining balance due of $87.5 million. As of September 30, 2008, the outstanding balance due was $87.5 million and the related accrued interest was $0.5 million. Subsequent to the September 30, 2008 quarter end, we paid an additional $15.0 million received on the environmental insurance policy. The deferral agreement with J. Aron was further amended on October 11, 2008 and the outstanding balance of $72.5 million on that date was further deferred to July 31, 2009. Additional proceeds of $9.8 million received under the property insurance policy subsequent to October 11, 2008, were used to pay down the principle balance on the deferral amount to $62.7 million as of ~~June 30, 2008) which we owe to J. Aron.~~November 6, 2008. The following is a summary of the various deferral agreements with J. Aron agreed to further defer these payments to August 31, 2008 however; we are required to use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008 to prepay any portion of the deferred amount. As ofsince June ~~30, 2008 we were not required to repay any portion of the deferred amount.~~2007.


	•	On June 26, 2007, ~~Coffeyville Resources, LLC~~CRLLC and J. Aron ~~& Company~~ entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%.

	•	On July 11, 2007, ~~Coffeyville Resources, LLC~~CRLLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending ~~June~~September 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS


		Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.


	•	On July 26, 2007, ~~Coffeyville Resources, LLC~~CRLLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

	•	On August 23, 2007, ~~Coffeyville Resources, LLC~~CRLLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million


		payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%.


	•	On July 29, 2008, the Company entered into a revised letter agreement with J. Aron to defer further $87.5 million of the deferred payment amounts owed under the 2007 deferral agreements. The unpaid deferred amounts and all accrued and unpaid interest ~~are~~were due and payable in full on December 15, 2008. If the Company ~~incurs~~incurred aggregate indebtedness in an aggregate principal amount of at least $125.0 million by December 15, 2008, the maturity date ~~will~~would be automatically extended to July 31, 2009 provided also that there ~~has~~had been no default of the Company in the performance of its obligations under the revised letter agreement. GS and Kelso each agreed to guarantee one half of the deferred payment of $87.5 million. The Company ~~has~~ agreed to repay deferred amounts in an amount equal to the sum of $36.2 million plus all accrued and unpaid interest ($~~6.7~~7.1 million as of August 1,29, 2008) by no later than August 31, 2008. On August 29, 2008, pursuant to the agreement, we paid J. Aron $36.2 million plus $7.1 million of accrued interest.

	•	On October 11, 2008, the Company and J. Aron entered into a revised letter agreement to defer the outstanding balance of $72.5 million and all accrued and unpaid interest to July 31, 2009. However, all accrued interest through December 15, 2008 must be paid on that day. Interest will accrue on the amounts deferred at the rate of (i) LIBOR plus 2.75% until December 15, 2008 and (ii) LIBOR plus 5.00%-7.50% (depending on J. Aron’s cost of capital) from December 15, 2008 through the date of payment. CRLLC must make prepayments of $5.0 million for the quarters ending March 31, 2009 and June 30, 2009 to reduce the deferred amounts. To the extent that CRLLC or any of its subsidiaries receives net insurance proceeds related to the July 2007 flood that they are not required to use to prepay CRLLC’s credit agreement or permitted to invest pursuant to the terms of CRLLC’s credit agreement, all net insurance proceeds will be used to prepay the deferred amounts. GS and Kelso each agreed to guarantee one half of the deferred payment obligations.

Beginning on August 31, 2008, interest shall accrue and be payable on the unpaid deferred amount of $87.5 million at the rate of LIBOR plus 2.75%. Under the terms of the deferral, the Company will be required to use the substantial majority of any gross proceeds from indebtedness for borrowed money incurred by the Company or certain of its subsidiaries, including the pending convertible debt offering, in excess of $125.0 million, to prepay a portion of the deferred amounts. There is no certainty that the convertible debt offering will be completed. The revised agreement requires the Company to prepay the deferred amount each quarter with the greater of 50% of free cash flow or $5.0 million. Any failure to make the quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts.

Capital Spending

In 2007, as a result of the flood, our refinery exceeded the required average annual gasoline sulfur standard as mandated by our approved hardship waiver with the EPA. In anticipation of a settlement with the EPA to resolve the non-compliance, the Company planned to spend $28.0 million in capital required for interim compliance with the ultra low sulfur gasoline standards in 2008, ahead of the required full compliance date of January 1, 2011. ~~The Company anticipates final resolution~~As a result of continued discussions with the EPA ~~during 2008. Accordingly, $10.1~~and its verbal agreement to modify the required average annual gasoline sulfur standard as a result of the flood, approximately $11.7 million of the originally planned capital spending of $28.0 million for the interim period has been deferred to 2009. Management is also evaluating whether any other capital spending projects can be deferred to a later date.

The Nitrogen Fertilizer business ~~is currently~~has been moving forward with an approximately $120 million fertilizer plant expansion which was originally expected to be completed in July 2010. Most recently the expected completion date was delayed to December 2010. As of ~~which~~September 30, 2008 approximately ~~$14.5~~$21.6 million was incurred aswith respect to the fertilizer plant expansion. Management is currently evaluating whether to proceed with an expected

completion date of ~~June 30, 2008. We estimate~~December 2010 or to delay any further work on this ~~expansion will increase the nitrogen fertilizer plant’s capacity~~project to ~~upgrade ammonia into premium priced UAN by approximately 50%. Management currently expects~~a later date. Whether management decides to ~~complete this expansion in July 2010. This project is also expected~~move forward depends on a number of factors including but not limited to ~~improve the cost structure~~current credit market conditions, further analysis and review of the ~~nitrogen fertilizer business by eliminating the need for~~costs of continued rail car shipments of ammonia ~~thereby avoiding anticipated cost increases in such transport.~~as well as the expected premium on UAN sales.

We will continue to evaluate all proposed projects and the related capital plan and make modifications as deemed appropriate with the ever-changing market. We currently do not anticipate any significant modification will be made to the capital plan unless there is a decision to postpone the fertilizer plant expansion.

Cash Flows

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


	Six Months Ended						Nine Months Ended
	June 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)						(Unaudited)

Net cash provided by (used in):
Operating activities	$	23,318		$	160,693		$	104.8		$	165.7
Investing activities		(49,635	)		(214,053	)		(67.4	)		(239.7	)
Financing activities		16,424			34,518			(8.0	)		59.4

Net (decrease) in cash and cash equivalents	$	(9,893	)	$	(18,842	)
Net increase (decrease) in cash and cash equivalents							$	29.4		$	(14.6	)

Cash Flows Provided by Operating Activities

Net cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$23.3~~$104.8 million compared to cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2007 of ~~$160.7~~$165.7 million. The positive cash flow from operating activities generated over the ~~six~~nine months ended ~~June~~September 30, 2008 was primarily driven by net income, ~~favorable changes in other working capital,~~ partially offset by unfavorable changes in trade working capital and other ~~assets and liabilities~~working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net income for the ~~six~~nine months ended ~~June~~September 30, 2008 included both the realized losses and the unrealized ~~losses~~gains on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of ~~June~~September 30, 2008 (approximately ~~two years)~~one year and nine months), the unrealized ~~losses~~gains on the Cash Flow Swap significantly ~~decreased~~increased our net income over this period. The impact of the realized losses and unrealized ~~losses~~gains on the Cash Flow Swap is apparent in the ~~$67.7~~$86.1 million ~~increase~~decrease in the payable to swap counterparty. Trade working capital for the ~~six~~nine months ended ~~June~~September 30, 2008 resulted in a use of cash of ~~$131.0~~$32.7 million. For the ~~six~~nine months ended ~~June~~September 30, 2008, accounts receivable increased ~~$54.5~~$47.5 million, inventory increased by ~~$71.8~~$11.4 million and accounts payable ~~decreased~~increased by ~~$4.7~~$26.2 million.

Net cash flows provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2007 was ~~$160.7~~$165.7 million. The positive cash flow from operating activities during this period was primarily the result of favorable changes in other working capital and trade working capital, partially offset by unfavorable changes in other assets and liabilities. Net loss for the period was not indicative of the operating margins for the period. This was the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net loss for the ~~six~~nine months ended ~~June~~September 30, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of ~~June~~September 30, 2007 (approximately ~~three years)~~two years and nine months), the realized and unrealized losses on the Cash Flow Swap significantly increased our net loss over this period. The impact of these realized and unrealized losses on the Cash Flow Swap is apparent in the ~~$276.6~~$230.9 million increase in the payable to swap

counterparty. Adding to our operating cash flow for the ~~six~~nine months ended ~~June~~September 30, 2007 was a ~~$3.9~~$43.2 million source of cash related to a decrease in trade working capital. For the ~~six~~nine months ended ~~June~~September 30, 2007, accounts receivable ~~increased $6.4~~decreased $4.2 million, inventory increased ~~$17.8~~$48.4 million and accounts payable increased ~~$28.1~~$87.4 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2008 was ~~$49.6~~$67.4 million compared to ~~$214.1~~$239.7 million for the ~~six~~nine months ended ~~June~~September 30, 2007. The decrease in investing activities was the result of decreased capital expenditures associated with various capital projects that commenced in the first quarter of 2007 in conjunction with the refinery turnaround. The majority of these capital projects, with the exception of the continuous catalytic reforming unit, were completed during the ~~six~~nine months ended ~~June~~September 30, 2007.

Cash Flows ~~Provided by~~Used In Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2008 was $8.0 million as compared to net cash provided by financing activities ~~for the six months ended June 30, 2008 was $16.4 million as compared to $34.5~~of $59.4 million for the ~~six~~nine months ended ~~June~~September 30, 2007. During the ~~six~~nine months ended ~~June~~September 30, 2008, ~~and June~~the principal use of cash related to scheduled principal payments of $3.7 million on long-term debt. The primary sources of cash for the nine months ended September 30, 2007 were obtained through net borrowings under the ~~primary source~~revolving credit facility of ~~cash was~~$20.0 million and borrowings obtained from the $25.0 million secured and the $25.0 million unsecured credit facilities obtained to provide additional liquidity during the completion of our restoration efforts for the refinery and nitrogen operations as a result of ~~borrowings drawn~~the flood. During the nine months ended September 30, 2007, we also paid $3.9 million of scheduled principal payments on ~~our revolving credit facility.~~long-term debt.

Working Capital

Working capital at ~~June~~September 30, 2008, was ~~$(35.5)~~$73.6 million, consisting of ~~$634.3~~$607.9 million in current assets and ~~$669.8~~$534.3 million in current liabilities. Working capital at December 31, 2007 was $10.7 million, consisting of $570.2 million in current assets and $559.5 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of ~~$91.1~~$115.1 million at ~~June 30, 2008.~~

~~Working capital was negatively impacted due to the reclassification of a portion of the insurance receivable related to the 2007 flood from current to non-current as of June~~September 30, 2008.

Letters of Credit

Our revolving credit facility provides for the issuance of letters of credit. At ~~June~~September 30, 2008, there were ~~$37.4~~$34.9 million of irrevocable letters of credit outstanding, including ~~$5.8~~$3.3 million in support of certain environmental obligators and $31.6 million to secure transportation services for crude oil.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of ~~June~~September 30, 2008.

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement on Financial Accounting Standards (SFAS) No. 157,Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price).” The standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At ~~June~~September 30, 2008, the only financial assets and financial liabilities that are within the scope of SFAS 157 and measured at fair value on a recurring basis are the Company’s derivative instruments. See Note ~~14,~~15, “Fair Value Measurements.”

entity’s financial statements on a recurring basis (at least annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will not have a material impact on the Company’s financial position or earnings.

~~In May 2008, the FASB issued final FASB Staff Position (“FSP”) No. APB14-1,~~~~Accounting for Convertible Debt Instruments That May be Settled in Cash upon Conversion (Including Partial Cash Settlement)~~. The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,~~Accounting for Derivative Instruments and Hedging Activities~~. Under the FSP, cash settled convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP is effective for financial statements issued for fiscal years and will require issuers of convertible debt that can be settled in cash to record the additional expense incurred. The Company is currently evaluating the FSP in conjunction with its convertible debt offering.

Critical Accounting Policies

The Company’s critical accounting policies are disclosed in the “Critical Accounting Policies” section of our Annual Report onForm 10-K/A for the year ended December 31, 2007. In addition to the accounting policies discussed in our 2007Form 10-K/A, the following accounting policy has been updated.

Receivables From Insurance

As of ~~June~~September 30, 2008, we have incurred total gross costs of approximately ~~$153.6~~$154.6 million as a result of the 2007 flood and crude oil discharge. During this period, we have maintained insurance policies that were issued by a variety of insurers and which covered various risks, such as property damage, interruption of our business, environmental cleanup costs, and potential liability to third parties for bodily injury or property damage. Accordingly, as of ~~June~~September 30, 2008, we have recognized receivables of approximately ~~$102.4~~$104.2 million related to these gross costs incurred that we believe are probable of recovery from the insurance carriers under the terms of the respective policies. As of ~~June~~September 30, 2008, we have collected approximately ~~$21.5~~$49.5 million of these receivables. ~~In July~~Subsequent to September 30, 2008 we received an additional ~~$13.0~~$9.8 million ~~from~~advance payment for unallocated property damage. As of November 6, 2008, the ~~Company’s property~~total amount of insurance ~~policy.~~recoveries received was $59.3 million.

We have submitted voluminous claims information to, and continue to respond to information requests from, ~~and negotiate with,~~ the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. Our property insurers have raised a question as to whether the Company’s facilities are principally located in “Zone A,” which was, at the time of the flood, subject to a $10 million insurance limit for flood, or “Zone B” which was, at the time of the flood, subject to a $300 million insurance limit for flood. The Company has reached an agreement with certain of its property insurers representing approximately 32.5% of its total property coverage for the flood-damaged facilities that our facilities are principally located in “Zone B” and therefore subject to the $300 million limit for flood. Our remaining property insurers have not, at this time, agreed to this position. In addition, our ~~primary~~excess environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup,” which is ~~subject to a $10 million sub-limit,~~not covered, rather than for “property damage,” which is covered to the limits of the policy. ~~The excess carrier has reserved its rights under the primary carrier’s position.~~ While we will vigorously contest the ~~primary~~excess carrier’s position, we contend that if that position were upheld, our umbrella ~~and excess~~ Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. Ultimate recovery will be subject to ~~continued negotiation as well as litigation.~~litigation which was filed in July 2008.

There is inherent uncertainty regarding the ultimate amount or timing of the recovery of the insurance receivable because of the difficulty in projecting the final resolution of our claims. The difference between what we ultimately receive under our insurance policies compared to the receivable we have recorded could be material to our consolidated financial statements.

Collective Bargaining Agreements

We are a party to collective bargaining agreements which as of ~~June~~September 30, 2008 ~~cover~~covered approximately ~~40%~~39% of our employees (all of whom work in our petroleum business) with the six unions of the Metal Trades ~~Union~~Department of the AFL-CIO (“Metal Trades Unions”) and the United Steelworkers of America. A new agreement was recently reached with the Metal Trade Union effective August 31, 2008. The ~~collective bargaining~~new agreement will expire in March 2013. No substantial changes were made to the agreement. The agreements with the United Steelworkers of America are scheduled to expire in March 2009.


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 ~~six~~nine months ended ~~June~~September 30, 2008 does not differ materially from that discussed under Part I — Item 3 of our Quarterly Report onForm 10-Q for the quarter ended March 31, 2008. We are exposed to market pricing for all of the products sold in the future both at our petroleum business and the nitrogen fertilizer business, as all of the products manufactured in both businesses are commodities. As of ~~June~~September 30, 2008, all ~~$508.3~~$485.5 million of outstanding debt under our credit facility was at floating rates; accordingly, an increase of 1.0% in the LIBOR rate would result in an increase in our interest expense of approximately ~~$5.2~~$4.9 million per year. None of our market risk sensitive instruments are held for trading.

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


Item 4.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures (Disclosure Controls) to ensure that information required to be disclosed in the Company’s reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Our Disclosure Controls were designed to provide reasonable assurance that the controls and procedures would meet their objectives. Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our Disclosure Controls will prevent all error and fraud. A control system, no matter how well designed and operated, can provide only reasonable assurance of achieving the designed control objectives and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of ~~simple~~human error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusions of two or more people, or by management override of the control. Because of the inherent limitations in ~~a cost-effective, maturing~~any control system, misstatements due to error or fraud may occur and not be detected.

Changes in Internal Control Over Financial Reporting

Part II. Other Information


Item 1.	*Legal Proceedings*

The following supplements and amends our discussion set forth under Item 3 “Legal Proceedings” in our Annual Report onForm 10-K/A for the fiscal year ended December 31, ~~2007.~~2007, and under Item 1 “Legal Proceedings” in our Quarterly Report onForm 10-Q for the quarter ended June 30, 2008.

WeAs described in our quarterly report onform 10-Q for the quarter ended June 30, 2008, we filed two lawsuits in the United States District Court for the District of Kansas on July 10, 2008 against certain of our insurance carriers with regard to our insurance coverage for the flood and crude oil discharge that occurred during the weekend of June 30, 2007. In Coffeyville Resources Refining & Marketing, LLC (CRRM), et al. v. National Union Fire Insurance Company of Pittsburgh, PA, et al., we are seeking a declaratory judgment against certain of our property insurers that our damaged facilities are located principally in “Zone B,” which was, at the time of the flood, subject to a $300 million insurance limit for flood, and not in “Zone A,” which was, at the time of the flood, subject to a $10 million flood insurance limit. Property insurers representing approximately 32.5% of our total property coverage for the flood have agreed with our position that our property is located principally in “Zone B” and ~~recently~~have signed a settlement agreement with us to the effect that our flood damaged property is principally located in the areas subject to the $300 million insurance limit for flood. In ~~Coffeyville Resources Refining & Marketing, LLC~~CRRM v. Liberty Surplus Insurance Corporation, et al., we ~~are suing~~sued our environmental insurance liability carriers for breach of contract on the grounds that our pollution liability claims are ~~primarily for “property damage,” which is~~ covered to the limits of our environmental pollution policies ~~rather than “cleanup,” which is subject to a $10 million sub-limit.~~and payment by the carriers under such policies has not been made. Our primary environmental liability carrier subsequently paid its full policy limit and has been dismissed from the pollution insurance case.


~~Item 1A.~~	*~~Risk Factors~~*

Item 1A. Risk Factors

See “Risk Factors” attached hereto as Exhibit 99.1 for a discussion of risks our business may face.


Item 4.	*~~Submission of Matters to a Vote of Security Holders~~*

At the annual meeting of the stockholders of the Company held on June 6, 2008, the following matters set forth in our Proxy Statement dated April 14, 2008 and amended May 19, 2008, each of which was filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, were voted upon with the results indicated below.

~~1. The nominees listed below were elected as directors with the respective votes set forth opposite each nominee’s name:~~

Director
Votes For Votes Withheld

John J. Lipinski 76,893,117 7,580,729
Scott L. Lebovitz 76,968,744 7,505,102
Regis B. Lippert 84,117,622 356,224
George E. Matelich 76,967,736 7,506,110
Steve A. Nordaker 84,186,935 286,911
Stanley de J. Osborne 76,968,373 7,505,473
Kenneth A. Pontarelli 76,967,379 7,506,467
Mark E. Tomkins 84,215,242 258,604

2. A proposal ratifying the appointment by the Company’s Audit Committee of KPMG LLP as the independent registered public accounting firm of the Company for the fiscal year ending December 31, 2008 was approved, with 84,420,576 votes cast FOR, 45,893 votes cast AGAINST and 7,377 abstentions.


~~Item~~ 6.	*Exhibits*

Number

Exhibit Title

10 .1 Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
10 .2 Letter Agreement between Coffeyville Resources, LLC and J. Aron & Company, dated as of July 29, 2008 (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K filed on August 4, 2008 and incorporated by reference herein)
10 .3 Amendment Agreement to the Company’s Amended and Restated Crude Oil Supply Agreement, dated as of July 31, 2008, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC
31 .1 Rule 13a — 14(a)/15d — 14(a) Certification of Chief Executive Officer
31 .2 Rule 13a — 14(a)/15d — 14(a) Certification of Chief Financial Officer
32 .1 Section 1350 Certification of Chief Executive Officer and Chief Financial Officer
99 .1 Risk Factors


Number			Exhibit Title

	10	.1	Amendment to Amended and Restated Crude Oil Supply Agreement, dated as of September 26, 2008, between Coffeyville Resources Refining & Marketing, LLC and J. Aron & Company.
	10	.2	Amended and Restated Settlement Deferral Letter, dated as of October 11, 2008, between Coffeyville Resources, LLC and J. Aron & Company.
	10	.3	First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of October 31, 2008, between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc.
	10	.4	Second Amendment to Amended and Restated Crude Oil Supply Agreement dated as of October 31, 2008, between Coffeyville Resources Refining & Marketing, LLC and J. Aron & Company.
	31	.1	Rule 13a — 14(a)/15d — 14(a) Certification of Chief Executive Officer
	31	.2	Rule 13a — 14(a)/15d — 14(a) Certification of Chief Financial Officer
	32	.1	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer
	99	.1	Risk Factors

6770

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, this 1413^th day of ~~August,~~November, 2008.

CVR Energy, Inc.


	By:	/s/ John J. Lipinski

Chief Executive Officer

(Principal Executive Officer)


	By:	/s/ James T. Rens

Chief Financial Officer

(Principal Financial Officer)

6871


	Three Months Ended June 30,								Six Months Ended June 30,
	2008				2007				2008				2007
	Barrels				Barrels				Barrels				Barrels
	per Day		%		per Day		%		per Day		%		per Day		%

Volumetric Data
Production:
Total gasoline		52,028		43.5		40,350		39.5		55,845		45.6		31,971		41.0
Total distillate		48,168		40.3		43,091		42.1		48,379		39.4		32,592		41.7
Total other		19,336		16.2		18,796		18.4		18,349		15.0		13,535		17.3

Total all production		119,532		100.0		102,237		100.0		122,573		100.0		78,098		100.0
Crude oil throughput		104,558		91.7		94,667		96.1		105,544		90.3		71,098		95.0
All other inputs		9,404		8.3		3,811		3.9		11,300		9.7		3,763		5.0

Total feedstocks		113,962		100.0		98,478		100.0		116,844		100.0		74,861		100.0


Director	Votes For		Votes Withheld

John J. Lipinski		76,893,117		7,580,729
Scott L. Lebovitz		76,968,744		7,505,102
Regis B. Lippert		84,117,622		356,224
George E. Matelich		76,967,736		7,506,110
Steve A. Nordaker		84,186,935		286,911
Stanley de J. Osborne		76,968,373		7,505,473
Kenneth A. Pontarelli		76,967,379		7,506,467
Mark E. Tomkins		84,215,242		258,604


Number			Exhibit Title

	10	.1	Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
	10	.2	Letter Agreement between Coffeyville Resources, LLC and J. Aron & Company, dated as of July 29, 2008 (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K filed on August 4, 2008 and incorporated by reference herein)
	10	.3	Amendment Agreement to the Company’s Amended and Restated Crude Oil Supply Agreement, dated as of July 31, 2008, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC
	31	.1	Rule 13a — 14(a)/15d — 14(a) Certification of Chief Executive Officer
	31	.2	Rule 13a — 14(a)/15d — 14(a) Certification of Chief Financial Officer
	32	.1	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer
	99	.1	Risk Factors