Exhibit 99.1

CVR Energy Reports Third Quarter Earnings
Of $109.3 Million, or $1.25 Per Share

SUGAR LAND, Texas (Nov. 2, 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 third quarter 2011 net income attributable to CVR Energy stockholders of $109.3 million, or $1.25 per fully diluted share, on net sales of $1,352.0 million. The 2011 results compared to net income of $23.2 million, or 27 cents per fully diluted share, on net sales of $1,031.2 million for the third quarter of 2010.

For the first nine months of 2011, the company reported net income attributable to CVR Energy stockholders of $279.9 million, or $3.19 per fully diluted share, on net sales of $3,966.9 million. This compares to net income of $12.0 million, or 14 cents per share, on net sales of $2,931.6 million, for the first nine months of 2010.

“Increased refining margins for petroleum products and solid prices for nitrogen fertilizers again drove strong quarterly results across CVR Energy,” said Chief Executive Officer Jack Lipinski.

“Refining margins continued strong in the third quarter, averaging $33.92 per barrel versus $9.01 per barrel in the same period just a year ago,” he said. “Meanwhile, agricultural commodity prices supported third quarter nitrogen fertilizer prices at levels well above their historical highs, averaging $294 per ton for our primary nitrogen fertilizer product, UAN (urea ammonium nitrate).”

Consolidated adjusted net income for the third quarter 2011was $137.4 million, or $1.57 per diluted share. Major items impacting the 2011 third quarter adjusted net income, all net of taxes, were an unfavorable impact from First In-First Out (FIFO) accounting of $15.8 million, share-based compensation of $1.5 million, major scheduled turnaround expense of $4.8 million and an unrealized loss on derivatives of $6.0 million.

For comparison, adjusted net income was $25.4 million in the third quarter of 2010. Major items impacting the 2010 third quarter adjusted net income, all net of taxes, were a favorable impact from FIFO of $2.1 million, share-based compensation of $3.3 million, major scheduled turnaround expense of $0.3 million and an unrealized loss on derivatives of $0.7 million.

As of Sept. 30, 2011, CVR Energy had cash and cash equivalents of $898.5 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 $37 million at the end of the third quarter 2011, compared to excess inventories of $14 million at the end of the year 2010.

On Oct. 27, 2011, the board of directors of the general partner of CVR Partners, LP declared a distribution of 57.2 cents per common unit, payable on Nov. 14, 2011, to unit holders of record on Nov. 7, 2011. This announced distribution will reduce by $12.6 million CVR Energy’s cash and cash equivalents held on the payment date.

Petroleum Business

The petroleum business reported third quarter 2011 operating income of $179.8 million on net sales of $1,284.4 million compared to operating income of $46.6 million on net sales of $986.2 million in the third quarter of 2010. The results for the third quarter 2011 reflected an unfavorable impact from FIFO accounting of $26.2 million, compared to a favorable impact of $3.5 million in the same period of 2010. For the first nine months of 2011, the petroleum segment had an operating income of $469.0 million compared to operating income of $44.1 million for the first nine months of 2010.

Additionally, in preparation of the refinery’s planned turnaround that began during the first week of October, the company decided to build finished goods inventory in order to meet marketing demands of our Coffeyville rack customers during the turnaround. This decision to carry sales from September to October impacted the gross profit for the third quarter of 2011 by approximately $8.0 million.

Adjusted EBITDA for the petroleum segment for the third quarter of 2011 was $232.0 million compared to adjusted EBITDA of $61.7 million in the third quarter of 2010.

For the third quarter of 2011, the refinery had total crude oil throughput of 112,885 barrels per day, compared with 118,351 barrels per day of crude oil throughput during the third quarter of 2010. Including all other feed and blend stocks, the refinery had total throughput of 116,091 barrels per day in the third quarter of 2011 compared to total throughput of 128,789 in the third quarter of 2010. Maintenance issues with the refinery’s fluid catalytic cracking unit and continuous catalytic reformer units during the third quarter accounted for the drop in throughput from last year’s third quarter.

Refining margin per crude oil throughput barrel was $25.03 in the third quarter of 2011 compared to $9.84 during the same period in 2010. Gross profit per crude oil throughput barrel was $18.14 in the third quarter of 2011 compared to $5.05 per crude oil throughput barrel during the same period in 2010.

Direct operating expense, exclusive of depreciation and amortization, for the third quarter of 2011 was $5.19 per barrel sold, as compared to $2.93 per barrel sold in the third quarter of 2010. This increase was primarily attributable to crude rate reductions, maintenance expenses and pre-turnaround activities.

Nitrogen Fertilizers Business

The fertilizer business reported third quarter 2011 operating income of $37.5 million on net sales of $77.2 million, compared to operating income of $10.6 million on net sales of $46.4 million during the equivalent period in 2010. For the first nine months of 2011, operating income was $93.6 million compared to operating income of $30.0 million in the first nine months of 2010.

Adjusted EBITDA for the fertilizer segment was $43.3 million in the third quarter of 2011 compared to adjusted EBITDA of $15.7 million for the same period in 2010.

On-stream factors for the nitrogen fertilizer plant in the third quarter 2011 were 99.2 percent for the gasifier, 98.6 percent for the ammonia synthesis loop and 97.0 percent for the UAN facility.

For the third quarter of 2011, average realized plant gate prices for ammonia and UAN were $568 per ton and $294 per ton respectively, compared to $317 per ton and $168 per ton respectively for the equivalent period in 2010.

The nitrogen fertilizer business produced 102,700 tons of ammonia during the third quarter of 2011, of which 25,900 net tons were available for sale while the rest was upgraded to 185,800 tons of more highly valued UAN. In the third quarter of 2010, the plant produced 112,600 tons of ammonia with 41,000 net tons available for sale and the remainder upgraded to 173,800 tons of UAN. The lower ammonia production in the third quarter of 2011 compared to the prior year’s third quarter reflects a price-neutral $5.7 million sale of hydrogen to the refinery in the 2011 period.

# # #

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 nine months ended September 30, 2011 and 2010. Select balance sheet data is as of September 30, 2011 and December 31, 2010.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in millions, except share data)
		(unaudited)
Consolidated Statement of Operations Data:
Net sales		$	1,352.0			$	1,031.2			$	3,966.9			$	2,931.6
Cost of product sold*			1,026.0				889.9				3,086.2				2,584.4
Direct operating expenses*			74.6				52.5				209.3				175.5
Insurance recovery — business interruption			(0.5	)			—				(3.4	)			—
Selling, general and administrative expenses*			17.7				16.4				69.0				48.6
Depreciation and amortization			22.0				21.9				66.1				64.8
Operating income		$	212.2			$	50.5			$	539.7			$	58.3
Interest expense and other financing costs			(13.8	)			(13.9	)			(41.2	)			(36.6	)
Gain (loss) on derivatives, net			(9.9	)			(1.0	)			(25.1	)			7.8
Loss on extinguishment of debt			—				—				(2.1	)			(15.1	)
Other income, net			0.4				0.5				1.4				2.4
Income before income tax expense		$	188.9			$	36.1			$	472.7			$	16.8
Income tax expense			68.6				12.9				172.5				4.8
Net income		$	120.3			$	23.2			$	300.2			$	12.0
Net income attributable to noncontrolling interest			11.0				—				20.3				—
Net income attributable to CVR Energy stockholders			109.3				23.2				279.9				12.0

Basic earnings per share		$	1.26			$	0.27			$	3.24			$	0.14
Diluted earnings per share		$	1.25			$	0.27			$	3.19			$	0.14
Weighted average common shares outstanding
Basic			86,549,846				86,343,102				86,462,668				86,336,205
Diluted			87,743,600				87,013,575				87,772,169				86,677,325

		As of September 30,				As of December 31,
		2011				2010
		(in millions)
		(unaudited)
Balance Sheet Data:
Cash and cash equivalents		$	898.5			$	200.0
Working capital			1,059.4				333.6
Total assets			2,508.3				1,740.2
Total debt, including current portion			591.8				477.0
Total CVR Energy stockholders’ equity			1,083.6				689.6
Noncontrolling interest			148.0				10.6

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in millions)
		(unaudited)
Other Financial Data:
Cash flows provided by operating activities		$	183.3			$	105.4			$	345.9			$	151.1
Cash flows used in investing activities			(23.1	)			(6.2	)			(43.8	)			(23.0	)
Cash flows provided by (used in) financing activities			(9.7	)			(0.1	)			396.3				(2.6	)
Net cash flow		$	150.5			$	99.1			$	698.4			$	125.5

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in millions, except per share data)
		(unaudited)
Non-GAAP Measures:
Reconciliation of Net Income to Adjusted Net Income:
Net Income attributable to CVR Energy stockholders		$	109.3			$	23.2			$	279.9			$	12.0
Adjustments:
FIFO impact (favorable) unfavorable, net of taxes (1)			15.8				(2.1	)			0.9				1.6
Share-based compensation, net of taxes (2)			1.5				3.3				16.5				7.1
Loss on extinguishment of debt, net of taxes (3)			—				—				1.2				9.1
Major scheduled turnaround expense, net of taxes (4)			4.8				0.3				7.4				0.4
Loss on disposition of assets, net of taxes (5)			—				—				0.9				0.8
Unrealized (gain) loss on derivatives, net of taxes (6)			6.0				0.7				4.1				(0.5	)
Adjusted net income (7)		$	137.4			$	25.4			$	310.9			$	30.5
Adjusted net income per diluted share		$	1.57			$	0.29			$	3.54			$	0.35

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in millions, except operating statistics)
		(unaudited)
Petroleum Business Financial Results:
Net sales		$	1,284.4			$	986.2			$	3,772.3			$	2,794.2
Cost of product sold*			1,024.5				879.0				3,077.5				2,560.1
Direct operating expenses* (8)(9)			54.5				35.3				144.0				114.8
Depreciation and amortization			17.0				16.9				50.9				49.5
Gross profit (10)		$	188.4			$	55.0			$	499.9			$	69.8
Plus direct operating expenses*			54.5				35.3				144.0				114.8
Plus depreciation and amortization			17.0				16.9				50.9				49.5
Refining margin (11)		$	259.9			$	107.2			$	694.8			$	234.1
FIFO impact (favorable) unfavorable (1)			26.2				(3.5	)			1.5				2.6
Refining margin adjusted for FIFO impact (12)		$	286.1			$	103.7			$	696.3			$	236.7
Operating income		$	179.8			$	46.6			$	469.0			$	44.1
Adjusted Petroleum EBITDA (13)		$	232.0			$	61.7			$	525.2			$	108.2
Petroleum Key Operating Statistics:
Per crude oil throughput barrel:
Refining margin (11)		$	25.03			$	9.84			$	23.77			$	7.63
FIFO impact (favorable) unfavorable (1)			2.52				(0.32	)			0.05				0.08
Refining margin adjusted for FIFO impact (12)			27.55				9.52				23.82				7.71
Gross profit (10)			18.14				5.05				17.10				2.28
Direct operating expenses* (8)			5.25				3.24				4.93				3.74
Direct operating expenses per barrel sold* (9)			5.19				2.93				4.71				3.38
Barrels sold (barrels per day) (9)			114,061				130,809				111,939				124,332

		Three Months Ended																Nine Months Ended
		September 30,																September 30,
		2011								2010								2011								2010
						(unaudited)																(unaudited)
Refining Throughput and Production Data:
(barrels per day)
Throughput:
Sweet			91,498				78.8	%			95,570				74.2	%			85,401				75.8	%			90,461				74.6	%
Light/medium sour			994				0.8	%			3,876				3.0	%			598				0.5	%			6,623				5.5	%
Heavy sour			20,393				17.6	%			18,905				14.7	%			21,071				18.7	%			15,272				12.6	%
Total crude oil throughput			112,885				97.2	%			118,351				91.9	%			107,070				95.0	%			112,356				92.7	%
All other feedstocks and blendstocks			3,206				2.8	%			10,438				8.1	%			5,671				5.0	%			8,960				7.3	%
Total throughput			116,091				100.0	%			128,789				100.0	%			112,741				100.0	%			121,316				100.0	%
Production:
Gasoline			49,886				42.7	%			62,432				48.1	%			50,998				45.0	%			59,168				48.3	%
Distillate			50,189				43.0	%			53,404				41.1	%			47,368				41.8	%			49,912				40.8	%
Other (excluding internally produced fuel)			16,770				14.3	%			14,049				10.8	%			15,038				13.2	%			13,294				10.9	%
Total refining production (excluding internally produced fuel)			116,845				100.0	%			129,885				100.0	%			113,404				100.0	%			122,374				100.0	%
Product price (dollars per gallon):
Gasoline		$	2.95							$	2.05							$	2.89							$	2.07
Distillate		$	3.07							$	2.13							$	3.04							$	2.12
Market Indicators (dollars per barrel):
West Texas Intermediate (WTI) NYMEX		$	89.54							$	76.21							$	95.47							$	77.69
Crude Oil Differentials:
WTI less WTS (light/medium sour)		$	0.82							$	2.16							$	2.46							$	1.96
WTI less WCS (heavy sour)		$	14.09							$	19.52							$	17.86							$	14.74
NYMEX Crack Spreads:
Gasoline		$	32.01							$	7.80							$	26.04							$	10.17
Heating Oil		$	35.82							$	10.22							$	28.51							$	9.35
NYMEX 2-1-1 Crack Spread		$	33.92							$	9.01							$	27.27							$	9.76
PADD II Group 3 Basis:
Gasoline		$	(0.03	)						$	1.27							$	(1.21	)						$	(1.42	)
Ultra Low Sulfur Diesel		$	2.54							$	2.91							$	2.32							$	1.74
PADD II Group 3 Product Crack:
Gasoline		$	31.98							$	9.06							$	24.82							$	8.75
Ultra Low Sulfur Diesel		$	38.36							$	13.13							$	30.82							$	11.08
PADD II Group 3 2-1-1		$	35.17							$	11.10							$	27.82							$	9.92

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions, except as noted)
						(unaudited)
Nitrogen Fertilizer Business Financial Results:
Net sales		$	77.2			$	46.4			$	215.3			$	141.1
Cost of product sold*			10.9				10.8				28.2				27.7
Direct operating expenses*			20.1				17.2				65.4				60.7
Insurance recovery — business interruption			(0.5	)			—				(3.4	)			—
Depreciation and amortization			4.7				4.5				13.9				13.9
Operating income		$	37.5			$	10.6			$	93.6			$	30.0
Adjusted Nitrogen Fertilizer EBITDA (13)		$	43.3			$	15.7			$	114.0			$	45.1
Nitrogen Fertilizer Key Operating Statistics:
Production (thousand tons):
Ammonia (gross produced) (14)			102.7				112.6				310.4				322.9
Ammonia (net available for sale) (14)			25.9				41.0				89.3				117.9
UAN			185.8				173.8				535.8				500.5
Petroleum coke consumed (thousand tons)			131.2				118.6				391.0				351.8
Petroleum coke (cost per ton)		$	43			$	26			$	30			$	19
Sales (thousand tons):
Ammonia			22.6				33.4				83.5				115.2
UAN			179.2				178.9				524.7				506.9
Total sales			201.8				212.3				608.2				622.1
Product pricing (plant gate) (dollars per ton) (15):
Ammonia		$	568			$	317			$	569			$	305
UAN		$	294			$	168			$	266			$	180
On-stream factors (16):
Gasification			99.2	%			99.2	%			99.5	%			95.8	%
Ammonia			98.6	%			99.0	%			98.0	%			94.6	%
UAN			97.0	%			96.9	%			95.9	%			92.2	%
Reconciliation to net sales (dollars in millions):
Freight in revenue		$	6.0			$	5.8			$	16.1			$	14.6
Hydrogen revenue			5.7				—				11.9				—
Sales net plant gate			65.5				40.6				187.3				126.5
Total net sales		$	77.2			$	46.4			$	215.3			$	141.1
Market Indicators:
Natural gas NYMEX (dollars per MMBtu)		$	4.06			$	4.38			$	4.21			$	4.52
Ammonia — Southern Plains (dollars per ton)		$	619			$	465			$	609			$	385
UAN — Mid Cornbelt (dollars per ton)		$	401			$	247			$	373			$	246

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 are the gross and tax affected FIFO impact for the applicable periods:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Petroleum:
FIFO impact (favorable) unfavorable		$	26.2			$	(3.5	)		$	1.5			$	2.6
Income tax expense (benefit) of FIFO			(10.4	)			1.4				(0.6	)			(1.0	)
FIFO impact (favorable) unfavorable, net of taxes		$	15.8			$	(2.1	)		$	0.9			$	1.6

(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 (“LTIP”). 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 the Partnership’s 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								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Share-based compensation recorded in direct operating expenses:
Petroleum		$	0.1			$	0.1			$	1.0			$	0.2
Nitrogen			0.1				0.1				0.4				0.2
Corporate			—				—				—				—
		$	0.2			$	0.2			$	1.4			$	0.4
Share-based compensation recorded in selling, general and administrative expenses:
Petroleum		$	0.7			$	1.1			$	7.0			$	2.2
Nitrogen			0.8				0.6				6.0				1.1
Corporate			0.7				2.0				9.3				4.7
		$	2.2			$	3.7			$	22.3			$	8.0
Share-based compensation recorded in other income			—				—				(0.1	)			—
Total share-based compensation		$	2.4			$	3.9			$	23.6			$	8.4
Income tax expense (benefit) of share-based compensation			(0.9	)			(0.6	)			(7.1	)			(1.3	)
Share-based compensation, net of taxes		$	1.5			$	3.3			$	16.5			$	7.1

(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 $2.1 million and was recognized as a loss on extinguishment of debt in our Consolidated Statement of Operations for the nine months ended September 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 are the gross and tax affected loss on extinguishment of debt for the applicable periods:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Loss on extinguishment of debt		$	—			$	—			$	2.1			$	15.1
Income tax expense (benefit) of loss on extinguishment of debt			—				—				(0.9	)			(6.0	)
Loss on extinguishment of debt, net of taxes		$	—			$	—			$	1.2			$	9.1

(4)

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Major schedule turnaround expense		$	8.0			$	0.4			$	12.2			$	0.6
Income tax expense (benefit) of turnaround expense			(3.2	)			(0.1	)			(4.8	)			(0.2	)
Major scheduled turnaround expense, net of taxes		$	4.8			$	0.3			$	7.4			$	0.4

(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 are the gross and tax affected impacts for the applicable periods:

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

(6)

The Company enters into commodity derivative transactions to manage price risk on crude oil and other inventories and to fix margins on certain future production. The Company has not designated their commodity derivative transactions as hedge transactions. All changes in fair market value are reported in earnings immediately. Below are the gross and tax affected impacts for the applicable periods:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Unrealized (gain)/loss on derivatives, net		$	10.0			$	1.2			$	6.8			$	(0.8	)
Income tax expense (benefit) of unrealized (gain)/loss on derivatives, net			(4.0	)			(0.5	)			(2.7	)			0.3
Unrealized (gain)/loss on derivatives, net of taxes		$	6.0			$	0.7			$	4.1			$	(0.5	)

(7)

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 nine months ended September 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, loss on disposition of fixed assets and unrealized (gain)/loss on derivatives, net. 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.
(8)		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.
(9)		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.
(10)		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.
(11)		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.
(12)		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.
(13)		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 nine months ended September 30, 2011 and 2010:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Petroleum:
Petroleum operating income (loss)		$	179.8			$	46.6			$	469.0			$	44.1
FIFO impacts (favorable), unfavorable			26.2				(3.5	)			1.5				2.6
Share-based compensation			0.8				1.2				8.0				2.4
Major scheduled turnaround expenses			8.0				0.4				12.2				0.6
Realized gain (loss) on derivatives, net			0.1				0.1				(18.3	)			7.1
Loss on disposition of assets			—				—				1.5				1.3
Depreciation and amortization			17.0				16.9				50.9				49.5
Other income (expense)			0.1				—				0.4				0.6
Adjusted Petroleum EBITDA		$	232.0			$	61.7			$	525.2			$	108.2

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
						(in millions)
						(unaudited)
Nitrogen Fertilizer:
Nitrogen Fertilizer operating income		$	37.5			$	10.6			$	93.6			$	30.0
Share-based compensation			0.9				0.7				6.4				1.3
Depreciation and amortization			4.7				4.5				13.9				13.9
Other income (expense)			0.2				(0.1	)			0.1				(0.1	)
Adjusted Nitrogen Fertilizer EBITDA		$	43.3			$	15.7			$	114.0			$	45.1

(14)		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.
(15)		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.
(16)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of the Linde air separation unit outage and the reactor outage, the on-stream factors would have been 99.2% for gasifier, 99.5% for ammonia, and 97.4% for UAN for three months ended September 30, 2010 and 98.0% for gasifier, 97.3% for ammonia, and 95.0% for UAN for nine months ended September 30, 2010. The on-stream factors would have been 100% for gasifier, 99.6% for ammonia, and 97.9% for UAN for three months ended September 30, 2011 and 99.8% for gasifier, 98.3% for ammonia, and 96.3% for UAN for nine months ended September 30, 2011, as adjusted to exclude the impact of a Linde air separation unit outage.

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.