UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		001-33492		61-1512186
(State or other jurisdiction of incorporation)		(Commission File Number)		(I.R.S. Employer Identification Number)

(Address of principal executive offices,
including zip code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 2.02. Results of Operations and Financial Condition.

     On August 3, 2011, CVR Energy, Inc. (the “Company”) issued a press release announcing information regarding its results of operations and financial condition for the quarter and six months ended June 30, 2011, the text of which is attached hereto as Exhibit 99.1 and is incorporated herein by reference.

     The information in Item 2.02 of this Current Report on Form 8-K and Exhibit 99.1 attached hereto is being “furnished” and is not deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section, nor is it deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits

The following exhibit is being “furnished” as part of this Current Report on Form 8-K:

99.1

Press release dated August 3, 2011, issued by CVR Energy, Inc.

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 hereunto duly authorized.

     Date: August 3, 2011

Exhibit 99.1

CVR Energy Posts Second Quarter Earnings
Of $124.9 Million, or $1.42 Per Share

SUGAR LAND, Texas (Aug. 3, 2011) — CVR Energy, Inc. (NYSE: CVI), a refiner and marketer of petroleum fuels and the majority owner of a nitrogen fertilizer products manufacturer, today reported second quarter 2011 net income attributable to CVR Energy stockholders of $124.9 million, or $1.42 per fully diluted share, on net sales of $1,447.7 million. The 2011 results compared to net income of $1.2 million, or 1 cent per fully diluted share, on sales of $1,005.9 million for the second quarter in 2010.

For the first six months of 2011, the company reported net income attributable to CVR Energy stockholders of $170.7 million, or $1.94 per fully diluted share, on net sales of $2,615.0 million compared to an $11.2 million loss, or a loss of 13 cents per share, on net sales of $1,900.4 million, for the first six months of 2010.

“Increased margins for petroleum products and improving prices for nitrogen fertilizers lifted us to record quarterly results,” said Chief Executive Officer Jack Lipinski. “Other than a reduction in crude run rates because of an issue with the continuous catalytic reformer (CCR) midway through the quarter, both plants ran well, allowing us to capture these high margins.

“In addition, early in the quarter we completed an initial public offering (IPO) of the CVR Partners, LP, nitrogen fertilizer master limited partnership, unlocking the value of that business and providing liquidity to grow the MLP,” Lipinski said. “CVR Energy retains 69.8 percent of the common units in this master limited partnership and will receive proportional distributions from CVR Partners.”

Consolidated adjusted net income for the second quarter 2011 was $130.3 million, or $1.48 per diluted share. Major items impacting the 2011 second quarter adjusted net income were an unfavorable impact from First In-First Out (FIFO) accounting, net of taxes, of $2.5 million; share-based compensation, net of taxes, of $1.3 million; and several other one-time adjustments totaling $1.6 million, after tax.

For comparison, adjusted net income was $19.2 million in the second quarter of 2010. Major items impacting the 2010 second quarter adjusted net income were an unfavorable impact from FIFO, net of taxes, of $10.6 million; a reversal of share-based compensation, net of taxes, of $2.2 million; and several other adjustments totaling $9.6 million.

As of June 30, 2011, CVR Energy had cash and cash equivalents of $748.0 million compared to cash and cash equivalents at year end 2010 of $200 million. In addition, the company carried excess crude oil and product inventories of $48 million at the end of the second quarter 2011, compared to excess inventories of $14 million at the end of the year 2010.

On July 26, 2011, the board of directors of the general partner of CVR Partners declared a distribution of 40.7 cents per common unit, payable on Aug. 12, 2011, to unit holders of record on Aug. 5, 2011. This announced distribution will reduce by $9.0 million CVR Energy’s cash and cash equivalents held on the payment date.

Petroleum Business

The petroleum business reported second quarter 2011 operating income of $183.5 million on net sales of $1,376.7 million compared to operating income of $4.6 million on net sales of $951.3 million in the second quarter of 2010. The results for the second quarter 2011 reflected an unfavorable impact from FIFO accounting of $4.1 million, compared to an unfavorable impact of $17.5 million in the same period of 2010. For the first six months of 2011, the petroleum segment had an operating income of $289.2 million compared to an operating loss of $2.4 million for the first six months in 2010.

Adjusted EBITDA for the petroleum segment for the second quarter of 2011 was $208.4 million compared to adjusted EBITDA of $46.5 million in the second quarter of 2010.

For the second quarter, the refinery had total crude oil throughput of 109,486 barrels per day, compared with 113,431 barrels per day of crude during the second quarter of 2010. Including all other feed and blend stocks, the refinery had total throughput of 116,459 barrels per day in the second quarter of 2011 compared to total throughput of 121,867 in the second quarter of 2010. Maintenance issues with the refinery’s CCR unit midway in the second quarter 2011 accounted for most of the drop in throughput.

Refining margin per crude oil throughput barrel was $25.49 in the second quarter of 2011 compared to $6.70 during the same period in 2010. Gross profit per crude oil throughput barrel was $19.36 in the second quarter of 2011 compared to $1.13 per crude oil throughput barrel during the same period in 2010.

Direct operating expense, exclusive of depreciation and amortization, for the second quarter 2011 was $4.09 per barrel sold, as compared to $3.63 per barrel sold in the second quarter of 2010. This increase was primarily attributable to higher prices in 2011 as well as unplanned maintenance costs related to the outage at the CCR during the quarter.

Nitrogen Fertilizers Business

The fertilizer business reported second quarter 2011 operating income of $39.3 million on net sales of $80.7 million, compared to operating income of $16.5 million on net sales of $56.3 million during the equivalent period in 2010. For the first six months of 2011, operating income was $56.1 million compared to operating income of $19.5 million in the first six months in 2010.

Adjusted EBITDA for the fertilizer segment was $45.0 million in the second quarter of 2011 compared to adjusted EBITDA of $20.6 million for the same period in 2010.

On-stream factors for the nitrogen fertilizer plant were 99.3 percent for the gasifier, 98.5 percent for the ammonia synthesis loop, and 97.6 percent for the UAN facility.

For the second quarter 2011, average realized plant gate prices for ammonia and UAN were $574 per ton and $300 per ton respectively, compared to $312 per ton and $205 per ton respectively for the equivalent period in 2010.

The nitrogen fertilizer business produced 102,300 tons of ammonia during the second quarter of 2011, of which 28,200 net tons were available for sale while the rest was upgraded to 179,400 tons of more highly valued UAN. In the 2010 second quarter, the plant produced 105,200 tons of ammonia with 38,700 net tons available for sale and the remainder upgraded to 162,900 tons of UAN.

# # #

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. You can generally identify forward-looking statements by our use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “seek,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. These forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. For a discussion of risk factors which may affect our results, please see the risk factors and other disclosures included in our Annual Report on Form 10-K for the year ended Dec. 31, 2010, and any subsequently filed quarterly reports on Form 10-Q. These risks may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Given these risks and uncertainties, you are cautioned not to place undue reliance on such forward-looking statements. The forward-looking statements included in this press release are made only as of the date hereof. The Company undertakes no duty to update its forward-looking statements.

About CVR Energy, Inc.

Headquartered in Sugar Land, Texas, CVR Energy, Inc.’s subsidiary and affiliated businesses include an independent refiner that operates a 115,000 barrel per day refinery in Coffeyville, Kan., and markets high value transportation fuels supplied to customers through tanker trucks and pipeline terminals, and a crude oil gathering system serving central Kansas, Oklahoma, western Missouri and southwest Nebraska. In addition, CVR Energy subsidiaries own a majority interest in and serve as the general partner of CVR Partners, LP, a producer of ammonia and urea ammonium nitrate, or UAN, fertilizers.

For further information, please contact:

Investor Relations:		Media Relations:
Jay Finks		Steve Eames
CVR Energy, Inc.		CVR Energy, Inc.
281-207-3588		281-207-3550
InvestorRelations@CVREnergy.com		MediaRelations@CVREnergy.com

CVR Energy, Inc.

The following tables summarize the financial data and key operating statistics for CVR Energy and our two operating segments for the three and six months ended June 30, 2011 and 2010. Select balance sheet data is as of June 30, 2011 and December 31, 2010.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions, except share data)
		(unaudited)
Consolidated Statement of Operations Data:
Net sales		$	1,447.7			$	1,005.9			$	2,615.0			$	1,900.4
Cost of product sold*			1,123.4				891.7				2,060.2				1,694.5
Direct operating expenses*			66.2				62.5				134.5				123.1
Insurance recovery — business interruption			—				—				(2.9	)			—
Selling, general and administrative expenses*			18.2				10.8				51.5				32.2
Net costs associated with flood			—				—				0.1				—
Depreciation and amortization			22.0				21.5				44.1				42.8
Operating income		$	217.9			$	19.4			$	327.5			$	7.8
Interest expense and other financing costs			(14.2	)			(12.8	)			(27.4	)			(22.7	)
Gain (loss) on derivatives, net			6.9				7.3				(15.2	)			8.8
Loss on extinguishment of debt			(0.2	)			(14.6	)			(2.1	)			(15.1	)
Other income, net			0.5				1.5				1.1				1.9
Income (loss) before income tax expense (benefit)		$	210.9			$	0.8			$	283.9			$	(19.3	)
Income tax expense (benefit)			76.7				(0.4	)			103.9				(8.1	)
Net income (loss)		$	134.2			$	1.2			$	180.0			$	(11.2	)
Net income (loss) attributable to noncontrolling interest			9.3				—				9.3				—
Net income (loss) attributable to CVR Energy stockholders		$	124.9			$	1.2			$	170.7			$	(11.2	)
*     Amounts shown are exclusive of depreciation and amortization.
Basic earnings (loss) per share		$	1.44			$	0.01			$	1.97			$	(0.13	)
Diluted earnings (loss) per share		$	1.42			$	0.01			$	1.94			$	(0.13	)
Weighted average common shares outstanding
Basic			86,422,881				86,336,125				86,418,356				86,332,700
Diluted			87,789,351				86,506,590				87,786,288				86,332,700

		As of June 30,				As of December 31,
		2011				2010
		(in millions)
		(unaudited)
Balance Sheet Data:
Cash and cash equivalents		$	748.0			$	200.0
Working capital			951.4				333.6
Total assets			2,349.9				1,740.2
Total debt, including current portion			591.7				477.0
Total CVR stockholders’ equity			973.4				689.6
Noncontrolling interest			146.5				10.6

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Other Financial Data:
Cash flows provided by operating activities		$	178.6			$	2.2			$	162.6			$	45.7
Cash flows used in investing activities			(13.6	)			(5.4	)			(20.7	)			(16.8	)
Cash flows provided by (used in) financing activities			417.1				28.9				406.0				(2.5	)
Net cash flow		$	582.1			$	25.7			$	547.9			$	26.4

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions except per share data)
		(unaudited)
Non-GAAP Measures:
Reconciliation of Net Income (loss) to Adjusted Net Income (loss):
Net Income (loss) attributable to CVR Energy stockholders		$	124.9			$	1.2			$	170.7			$	(11.2	)
Adjustments:
FIFO impact (favorable) unfavorable, net of taxes (1)			2.5				10.6				(12.9	)			3.1
Share-based compensation, net of taxes (2)			1.3				(2.2	)			15.0				3.6
Loss on extinguishment of debt, net of taxes (3)			0.1				8.7				1.3				9.1
Major scheduled turnaround expense, net of taxes (4)			0.6				0.1				2.5				0.1
Loss on disposition of fixed assets, net of taxes (5)			0.9				0.8				0.9				0.8
Adjusted net income (6)		$	130.3			$	19.2			$	177.5			$	5.5
Adjusted net income per diluted share		$	1.48			$	0.22			$	2.02			$	0.06

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions, except operating statistics)
		(unaudited)
Petroleum Business Financial Results:
Net sales		$	1,376.7			$	951.3			$	2,487.9			$	1,808.0
Cost of product sold*			1,122.8				882.1				2,053.0				1,681.1
Direct operating expenses * (7)(8)			44.0				41.2				89.4				79.5
Net costs associated with flood			—				—				0.1				—
Depreciation and amortization			17.0				16.4				33.9				32.6
Gross profit (9)		$	192.9			$	11.6			$	311.5			$	14.8
Plus direct operating expenses *			44.0				41.2				89.4				79.5
Plus net costs associated with flood			—				—				0.1				—
Plus depreciation and amortization			17.0				16.4				33.9				32.6
Refining margin (10)		$	253.9			$	69.2			$	434.9			$	126.9
FIFO impact (favorable) unfavorable (1)			4.1				17.5				(21.3	)			5.2
Refining margin adjusted for FIFO impact (11)		$	258.0			$	86.7			$	413.6			$	132.1
Operating income (loss)		$	183.5			$	4.6			$	289.2			$	(2.4	)
Adjusted Petroleum EBITDA (12)		$	208.4			$	46.5			$	296.6			$	45.5
Petroleum Key Operating Statistics:
Per crude oil throughput barrel:
Refining margin (10)		$	25.49			$	6.70			$	23.08			$	6.41
FIFO impact (favorable) unfavorable (1)			0.41				1.70				(1.13	)			0.26
Refining margin adjusted for FIFO impact (11)			25.90				8.40				21.95				6.67
Gross profit (9)			19.36				1.13				16.53				0.75
Direct operating expenses * (7)			4.42				3.99				4.74				4.02
Direct operating expenses per barrel sold* (8)			4.09				3.63				4.45				3.63
Barrels sold (barrels per day) (8)			118,435				124,486				110,860				121,016

		Three Months Ended																Six Months Ended
		June 30,																June 30,
		2011								2010								2011								2010
						(unaudited)																(unaudited)
Refining Throughput and Production Data:
(barrels per day)
Throughput:
Sweet			84,654				72.6	%			90,829				74.5	%			82,302				74.1	%			87,864				74.8	%
Light/medium sour			198				0.2	%			8,505				7.0	%			397				0.4	%			8,019				6.8	%
Heavy sour			24,634				21.2	%			14,097				11.6	%			21,416				19.3	%			13,425				11.4	%
Total crude oil throughput			109,486				94.0	%			113,431				93.1	%			104,115				93.8	%			109,308				93.0	%
All other feedstocks and blendstocks			6,973				6.0	%			8,436				6.9	%			6,923				6.2	%			8,209				7.0	%
Total throughput			116,459				100.0	%			121,867				100.0	%			111,038				100.0	%			117,517				100.0	%
Production:
Gasoline			53,495				45.5	%			55,998				45.7	%			51,564				46.2	%			57,508				48.5	%
Distillate			48,959				41.6	%			51,008				41.6	%			45,934				41.1	%			48,137				40.6	%
Other (excluding internally produced fuel)			15,106				12.9	%			15,607				12.7	%			14,158				12.7	%			12,911				10.9	%
Total refining production (excluding internally produced fuel)			117,560				100.0	%			122,613				100.0	%			111,656				100.0	%			118,556				100.0	%
Product price (dollars per gallon):
Gasoline		$	3.07							$	2.12							$	2.86							$	2.08
Distillate		$	3.14							$	2.17							$	3.03							$	2.12
Market Indicators (dollars per barrel):
West Texas Intermediate (WTI) NYMEX		$	102.34							$	78.05							$	98.50							$	78.46
Crude Oil Differentials:
WTI less WTS (light/medium sour)			2.51								1.84								3.30								1.86
WTI less WCS (heavy sour)			17.61								13.92								19.76								12.19
NYMEX Crack Spreads:
Gasoline			27.85								13.00								22.98								11.39
Heating Oil			25.56								10.50								24.76								8.89
NYMEX 2-1-1 Crack Spread			26.71								11.75								23.87								10.14
PADD II Group 3 Basis:
Gasoline			(1.59	)							(2.88	)							(1.82	)							(2.80	)
Ultra Low Sulfur Diesel			3.24								2.58								2.21								1.13
PADD II Group 3 Product Crack:
Gasoline			26.26								10.12								21.16								8.58
Ultra Low Sulfur Diesel			28.81								13.08								26.97								10.03
PADD II Group 3 2-1-1			27.53								11.60								24.06								9.31

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions, except as noted)
		(unaudited)
Nitrogen Fertilizer Business Financial Results:
Net sales		$	80.7			$	56.3			$	138.1			$	94.6
Cost of product sold*			9.7				11.9				17.2				16.9
Direct operating expenses *			22.3				21.3				45.3				43.5
Insurance recovery — business interruption			—				—				(2.9	)			—
Net cost associated with flood			—				—				—				—
Depreciation and amortization			4.7				4.7				9.3				9.3
Operating income		$	39.3			$	16.5			$	56.1			$	19.5
Adjusted Nitrogen Fertilizer EBITDA (12)		$	45.0			$	20.6			$	70.9			$	29.3
Nitrogen Fertilizer Key Operating Statistics:
Production (thousand tons):
Ammonia (gross produced) (13)			102.3				105.2				207.6				210.3
Ammonia (net available for sale) (13)			28.2				38.7				63.4				76.9
UAN			179.4				162.9				350.0				326.7
Petroleum coke consumed (thousand tons)			135.8				115.5				259.9				233.1
Petroleum coke (cost per ton)		$	30			$	17			$	23			$	15
Sales (thousand tons):
Ammonia			33.6				50.6				60.9				81.8
UAN			166.1				172.2				345.4				327.9
Total sales			199.7				222.8				406.3				409.7
Product pricing (plant gate) (dollars per ton) (14):
Ammonia		$	574			$	312			$	570			$	300
UAN		$	300			$	205			$	252			$	187
On-stream factors (15):
Gasification			99.3	%			92.2	%			99.6	%			94.0	%
Ammonia			98.5	%			90.4	%			97.6	%			92.3	%
UAN			97.6	%			89.1	%			95.4	%			89.8	%
Reconciliation to net sales (dollars in millions):
Freight in revenue		$	5.4			$	5.2			$	10.2			$	8.8
Hydrogen revenue			6.1				—				6.1				—
Sales net plant gate			69.2				51.1				121.8				85.8
Total net sales		$	80.7			$	56.3			$	138.1			$	94.6
Market Indicators:
Natural gas NYMEX (dollars per MMBtu)		$	4.38			$	4.35			$	4.29			$	4.67
Ammonia — Southern Plains (dollars per ton)		$	604			$	359			$	605			$	345
UAN — Mid Cornbelt (dollars per ton)		$	366			$	249			$	358			$	246

(1)		First-in, first-out (“FIFO”) is the Company’s basis for determining inventory value on a Generally Accepted Accounting Principles (“GAAP”) basis. 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 favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. Below is the gross and tax affected FIFO impact for the applicable periods:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Petroleum:
FIFO impact (favorable) unfavorable		$	4.1			$	17.5			$	(21.3	)		$	5.2
Income tax expense (benefit) of FIFO			(1.6	)			(6.9	)			8.4				(2.1	)
FIFO impact (favorable) unfavorable, net of taxes		$	2.5			$	10.6			$	(12.9	)		$	3.1

(2)		The Company has two classifications for share-based compensation awards. Phantom Unit Plan awards are accounted for as liability based awards. In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718, Compensation — Stock Compensation (“ASC 718”), the expense associated with these awards is based on the current fair value of the awards. These awards are remeasured at each reporting date until the awards are settled in their entirety. Override unit awards are accounted for as equity-classified awards using the guidance for non-employee awards prescribed by FASB Topic ASC 323 (“ASC 323”). ASC 323 includes guidance for the proper accounting by an investor for stock-based compensation granted to employees of an equity method investee. In addition, guidance set forth in FASB Topic ASC 505, provides the treatment related to accounting for equity investments that are issued other than to employees for acquiring, or in conjunction with selling goods or services. In accordance with that guidance, the expense associated with these awards is based on the current fair value of the awards. These awards are remeasured at each reporting date until the awards are vested (when the performance commitment is reached). The value of all of these awards can fluctuate significantly between periods. Subsequent to the second quarter of 2011, there will be no further compensation expense recorded associated with the Phantom Unit Plan awards and the override unit awards as both types of awards were settled in their entirety in the second quarter of 2011.
		Non-vested common stock awards are accounted for as equity-classified awards using the guidance provided by ASC 718. Non-vested common stock awards upon issuance typically vest over a three year period. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the award. In connection with the initial public offering of CVR Partners, LP (the “Partnership”) in April 2011, the board of directors of the general partner of the Partnership adopted a Long-Term Incentive Plan. Compensation expense associated with the fair value of these awards is amortized over the vesting period of the award.
		The compensation expense associated with our Phantom Unit Plan, override units, non-vested common stock awards, and CVR Partners’ LTIP awards is recorded in direct operating expenses, selling, general and administration expenses and other income. Below is a breakdown of the expense by Statement of Operations caption and by business segment.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Share-based compensation recorded in direct operating expenses:
Petroleum		$	0.1			$	(0.1	)		$	0.8			$	0.1
Nitrogen			—				(0.1	)			0.4				0.1
Corporate			—				—				—				—
		$	0.1			$	(0.2	)		$	1.2			$	0.2
Share-based compensation recorded in selling, general and administrative expenses:
Petroleum		$	0.4			$	(0.9	)		$	6.3			$	1.1
Nitrogen			0.9				(0.4	)			5.1				0.5
Corporate			0.8				(1.3	)			8.7				2.6
		$	2.1			$	(2.6	)		$	20.1			$	4.2
Share-based compensation recorded in other income			(0.1	)			—				(0.1	)			—
Total share-based compensation		$	2.1			$	(2.8	)		$	21.2			$	4.4
Income tax expense (benefit) of share-based compensation			(0.8	)			0.6				(6.2	)			(0.8	)
Share-based compensation, net of taxes		$	1.3			$	(2.2	)		$	15.0			$	3.6

(3)		In February 2011, the Company entered into an asset-backed revolving credit facility (“ABL credit facility”) and concurrently terminated its first priority credit facility. In connection with the terminated first priority credit facility, the Company recorded a loss on extinguishment of debt of approximately $1.9 million of previously deferred financing costs. In May 2011, the Company repurchased $2.7 million of its Senior Notes (“Notes”) at 103% of the aggregate principal balance. This repurchase was in conjunction with a tender offer in accordance with the terms of the Notes due to the initial public offering of CVR Partners. The premium and previously deferred financing costs associated with the Notes repurchased, approximated $0.2 million and was recognized as a loss on extinguishment of debt in our Consolidated Statement of Operations for the three months ended June 30, 2011. In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. The premiums paid are reflected as a loss on extinguishment of debt in our Consolidated Statements of Operations. In April 2010, we paid off the remaining $453.0 million tranche D term loans. This payoff was made possible by the issuance of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million. In addition, previously deferred borrowing costs totaling approximately $5.4 million associated with the first priority credit facility term debt were also written off at that time. The Company also recognized approximately $0.1 million of third party costs at the time the Notes were issued. Other third party costs incurred at the time were deferred and will be amortized over the respective terms of the Notes. The premiums paid, previously deferred borrowing costs subject to write-off and immediately recognized third party expenses are reflected as a loss on extinguishment of debt

		in our Condensed Consolidated Statements of Operations. Below is the gross and tax affected loss on extinguishment of debt for the applicable periods:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Loss on extinguishment of debt		$	0.2			$	14.6			$	2.1			$	15.1
Income tax benefit of loss on extinguishment of debt			(0.1	)			(5.9	)			(0.8	)			(6.0	)
Loss on extinguishment of debt, net of taxes		$	0.1			$	8.7			$	1.3			$	9.1

(4)		Represents expenses associated with a major scheduled turnaround for the refinery.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Major schedule turnaround expense		$	1.1			$	0.2			$	4.3			$	0.2
Income tax benefit of turnaround expense			(0.5	)			(0.1	)			(1.8	)			(0.1	)
Major scheduled turnaround expense, net of taxes		$	0.6			$	0.1			$	2.5			$	0.1

(5)		During the second quarter of 2011, the Company wrote-off amounts associated with certain Petroleum fixed assets. During the second quarter of 2010, the Company wrote-off an amount associated with a capital project. Below is the gross and tax effected impacts for the applicable periods:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Loss on disposition of assets		$	1.5			$	1.3			$	1.5			$	1.3
Income tax (benefit) of loss on disposition of assets			(0.6	)			(0.5	)			(0.6	)			(0.5	)
Loss on disposition of assets, net of taxes		$	0.9			$	0.8			$	0.9			$	0.8

(6)		Adjusted net income results from adjusting net income for items that the Company believes are needed in order to evaluate results in a more comparative analysis from period to period. For the three and six months ended June 30, 2011 and 2010, these items included, on an after tax basis, the Company’s impact of the accounting for its inventory under FIFO, share-based compensation, loss on extinguishment of debt, major scheduled turnaround expenses and loss on disposition of fixed assets. Adjusted net income is not a recognized term under GAAP and should not be substituted for net income (loss) as a measure of our performance but rather should be utilized as a supplemental measure of financial performance in evaluating our business. Management believes that adjusted net income provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.

(7)		Direct operating expense is presented on a per crude oil throughput basis. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period to derive the metric.
(8)		Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refinery. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.
(9)		In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.
(10)		Refining margin per crude oil throughput barrel 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) can be taken directly from our Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. 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. We believe that refining margin is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.
(11)		Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) adjusted for FIFO impacts. 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 favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. Refining margin adjusted for FIFO impact 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 (taking into account the impact of our utilization of FIFO) that we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.
(12)		Adjusted Petroleum and Nitrogen Fertilizer EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, loss on disposition of fixed assets, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the petroleum and nitrogen fertilizer segments for the three and six months ended June 30, 2011 and 2010:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Petroleum:
Petroleum operating income (loss)		$	183.5			$	4.6			$	289.2			$	(2.4	)
FIFO impacts (favorable), unfavorable			4.1				17.5				(21.3	)			5.2
Share-based compensation			0.5				(1.0	)			7.1				1.2
Major scheduled turnaround expenses			1.1				0.2				4.3				0.2
Realized gain (loss) on derivatives, net			0.5				6.9				(18.4	)			6.9
Loss on disposition of fixed assets			1.5				1.3				1.5				1.3
Depreciation and amortization			17.0				16.4				33.9				32.6
Other income (expense)			0.2				0.6				0.3				0.5
Adjusted Petroleum EBITDA		$	208.4			$	46.5			$	296.6			$	45.5

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Nitrogen Fertilizer:
Nitrogen Fertilizer operating income		$	39.3			$	16.5			$	56.1			$	19.5
Share-based compensation			0.9				(0.5	)			5.5				0.6
Major scheduled turnaround expenses			—				—				—				—
Depreciation and amortization			4.7				4.7				9.3				9.3
Other income (expense)			0.1				(0.1	)			—				(0.1	)
Adjusted Nitrogen Fertilizer EBITDA		$	45.0			$	20.6			$	70.9			$	29.3

(13)		The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN.
(14)		Plant gate sales per ton represent net sales less freight and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.
(15)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.

Use of Non-GAAP Financial Measures

To supplement the actual results in accordance with GAAP for the applicable periods, the Company also uses non-GAAP measures as discussed above, which are adjusted for GAAP-based results. The use of non-GAAP adjustments are not in accordance with or an alternative for GAAP. The adjustments are provided to enhance an overall understanding of the Company’s financial performance for the applicable periods and are indicators management believes are relevant and useful for planning and forecasting future periods.