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 ý No o

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

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

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

There were 86,831,050 shares of the registrant's common stock outstanding at August 1, 2012.

2-1-1 crack spread—The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.

ammonia—Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.

backwardation market—Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango market.

barrel—Common unit of measure in the oil industry which equates to 42 gallons.

blendstocks—Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.

bulk sales—Volume sales through third party pipelines, in contrast to tanker truck quantity sales.

capacity—Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints.

catalyst—A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

coker unit—A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke.

contango market—Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation market.

corn belt—The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.

crack spread—A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.

ethanol—A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.

farm belt—Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.

feedstocks—Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

heavy crude oil—A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.

independent petroleum refiner—A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.

light crude oil—A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.

Magellan—Magellan Midstream Partners L.P., a publicly traded company whose business is the transportation, storage and distribution of refined petroleum products.

MMBtu—One million British thermal units or Btu: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.

natural gas liquids—Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and are products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.

PADD II—Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.

Partnership IPO—The initial public offering of 22,080,000 common units representing limited partner interests of CVR Partners, LP (the "Partnership"), which closed on April 13, 2011.

plant gate price—The unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs.

petroleum coke (pet coke)—A coal-like substance that is produced during the refining process.

refined products—Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

sour crude oil—A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

spot market—A market in which commodities are bought and sold for cash and delivered immediately.

sweet crude oil—A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

throughput—The volume processed through a unit or a refinery or transported on a pipeline.

turnaround—A periodically required standard procedure to inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for our refineries and every two years for the nitrogen fertilizer plant.

UAN—An aqueous solution of urea and ammonium nitrate used as a fertilizer.

wheat belt—The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas.

WCS—Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.

WTI—West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity, between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

WTS—West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.

Wynnewood Acquisition—The acquisition by the Company of all the outstanding shares of the Gary-Williams Energy Corporation and its subsidiaries ("GWEC"), which owns the 70,000 bpd Wynnewood, Oklahoma refinery and 2.0 million barrels of storage tanks, on December 15, 2011. GWEC was subsequently converted to Gary-Williams Energy Company, LLC and is now known as Wynnewood Energy Company, LLC.

yield—The percentage of refined products that is produced from crude oil and other feedstocks.

	June 30, 2012			December 31, 2011

	(unaudited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	692,588		$	388,328
Accounts receivable, net of allowance for doubtful accounts of $1,370 and $1,282, respectively		214,296			182,619
Inventories		514,309			636,221
Prepaid expenses and other current assets		64,805			117,509
Insurance receivable		1,926			1,939
Deferred income taxes		26,063			—
Income tax receivable		—			30,167

Total current assets		1,513,987			1,356,783
Property, plant, and equipment, net of accumulated depreciation		1,701,305			1,672,961
Intangible assets, net		297			312
Goodwill		40,969			40,969
Deferred financing costs, net		17,437			20,319
Insurance receivable		4,076			4,076
Other long-term assets		6,643			23,871

Total assets	$	3,284,714		$	3,119,291

LIABILITIES AND EQUITY
Current liabilities:
Note payable and capital lease obligations	$	3,309		$	9,880
Accounts payable		426,818			466,559
Personnel accruals		39,774			20,849
Accrued taxes other than income taxes		36,316			35,147
Income taxes payable		30,840			2,400
Due to parent		28,335			—
Deferred income taxes		—			9,271
Deferred revenue		4,375			9,026
Other current liabilities		39,723			34,427

Total current liabilities		609,490			587,559
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion		851,911			853,903
Accrued environmental liabilities, net of current portion		1,373			1,459
Deferred income taxes		380,139			357,473
Other long-term liabilities		20,947			19,194

Total long-term liabilities		1,254,370			1,232,029
Commitments and contingencies
Equity:
CVR stockholders' equity:
Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 and 86,906,760 shares issued as of June 30, 2012 and December 31, 2011, respectively		869			869
Additional paid-in-capital		582,735			587,199
Retained earnings		696,387			566,855
Treasury stock, 98,610 shares as of June 30, 2012 and December 31, 2011, respectively, at cost		(2,303	)		(2,303	)
Accumulated other comprehensive income, net of tax		(1,216	)		(1,008	)

Total CVR stockholders' equity		1,276,472			1,151,612

Noncontrolling interest		144,382			148,091

Total equity		1,420,854			1,299,703

Total liabilities and equity	$	3,284,714		$	3,119,291

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2011			2012			2011
	(unaudited) (in thousands, except share data)
Net sales	$	2,308,318		$	1,447,716		$	4,276,949		$	2,614,981
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		1,874,210			1,123,375			3,509,365			2,060,197
Direct operating expenses (exclusive of depreciation and amortization)		94,099			66,207			209,613			134,641
Insurance recovery—business interruption		—			—			—			(2,870	)
Selling, general and administrative expenses (exclusive of depreciation and amortization)		72,047			18,171			117,389			51,433
Depreciation and amortization		32,190			22,043			64,302			44,054

Total operating costs and expenses		2,072,546			1,229,796			3,900,669			2,287,455

Operating income		235,772			217,920			376,280			327,526
Other income (expense):
Interest expense and other financing costs		(18,974	)		(14,205	)		(38,227	)		(27,395	)
Interest income		133			211			223			485
Realized gain (loss) on derivatives, net		(8,069	)		483			(27,155	)		(18,364	)
Unrealized gain (loss) on derivatives, net		46,886			6,449			(81,281	)		3,190
Loss on extinguishment of debt		—			(170	)		—			(2,078	)
Other income, net		709			246			826			477

Total other income (expense)		20,685			(6,986	)		(145,614	)		(43,685	)

Income before income taxes		256,457			210,934			230,666			283,841
Income tax expense		91,099			76,738			81,353			103,857

Net income		165,358			134,196			149,313			179,984
Less: Net income attributable to noncontrolling interest		10,624			9,331			19,781			9,331

Net income attributable to CVR Energy stockholders	$	154,734		$	124,865		$	129,532		$	170,653

Basic earnings per share	$	1.78		$	1.44		$	1.49		$	1.97
Diluted earnings per share	$	1.75		$	1.42		$	1.46		$	1.94
Weighted-average common shares outstanding:
Basic		86,821,224			86,422,881			86,814,687			86,418,356
Diluted		88,454,006			87,789,351			88,464,347			87,786,288

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended June 30,					Six Months Ended June 30,

	2012			2011		2012			2011
	(unaudited) (in thousands)
Net income	$	165,358		$	134,196	$	149,313		$	179,984
Other comprehensive income (loss):
Unrealized gain (loss) on available-for-sale securities, net of tax of $0 and $0		1			—		2			(1	)
Change in fair value of interest rate swap, net of tax of $(202) $0, $(264) and $0		(524	)		—		(697	)		—
Reclass of gain/loss to income on settlement of interest rate swap, net of tax of $67, $0, $128 and $0		167			—		337			—

Total other comprehensive income (loss)		(356	)		—		(358	)		(1	)

Comprehensive income		165,002			134,196		148,955			179,983
Less: Comprehensive income attributable to noncontrolling interest		10,475			9,331		19,631			9,331

Comprehensive income attributable to CVR stockholders	$	154,527		$	124,865	$	129,324		$	170,652

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Common Stockholders

	Shares Issued		$0.01 Par Value Common Stock		Additional Paid-In Capital			Retained Earnings		Treasury Stock			Accumulated Other Comprehensive Income (loss)			Total CVR Stockholders' Equity			Noncontrolling Interest			Total Equity
	(unaudited) (in thousands, except share data)
Balance at December 31, 2011		86,906,760	$	869	$	587,199		$	566,855	$	(2,303	)	$	(1,008	)	$	1,151,612		$	148,091		$	1,299,703
Distributions to noncontrolling interest holders		—		—		—			—		—			—			—			(24,565	)		(24,565	)
Share-based compensation		—		—		5,148			—		—			—			5,148			1,225			6,373
Modification and reclassification of equity share-based compensation award to a liability based award		—		—		(9,924	)		—		—			—			(9,924	)		—			(9,924	)
Excess tax benefit from share-based compensation		—		—		(12	)		—		—			—			(12	)		—			(12	)
Exercise of stock options		22,900		—		413			—		—			—			413			—			413
Redemption of common units		—		—		(89	)		—		—			—			(89	)		—			(89	)
Net income		—		—		—			129,532		—			—			129,532			19,781			149,313
Net unrealized gain on available-for-sale securities, net of tax		—		—		—			—		—			2			2			—			2
Net loss on interest rate swaps, net of tax		—		—		—			—		—			(210	)		(210	)		(150	)		(360	)

Balance at June 30, 2012		86,929,660	$	869	$	582,735		$	696,387	$	(2,303	)	$	(1,216	)	$	1,276,472		$	144,382		$	1,420,854

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,

	2012			2011
	(unaudited)
	(in thousands)
Cash flows from operating activities:
Net income	$	149,313		$	179,984
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		64,302			44,054
Allowance for doubtful accounts		88			164
Amortization of deferred financing costs		3,913			2,084
Amortization of original issue discount		270			255
Amortization of original issue premium		(1,741	)		—
Deferred income taxes		(12,479	)		8,122
Excess tax benefit from share-based compensation		(12	)		—
Loss on disposition of assets		872			2,177
Loss on extinguishment of debt		—			2,078
Share-based compensation		21,922			21,220
Unrealized (gain) loss on derivatives, net		81,281			(3,190	)
Changes in assets and liabilities:
Accounts receivable		(31,220	)		(18,147	)
Inventories		121,912			(68,774	)
Prepaid expenses and other current assets		(9,485	)		(13,847	)
Insurance receivable		13			(8,969	)
Business interruption insurance proceeds		—			2,870
Other long-term assets		(1,596	)		(970	)
Accounts payable		(27,583	)		5,187
Due to parent		28,335			—
Accrued income taxes		58,607			30,139
Deferred revenue		(4,651	)		(15,697	)
Other current liabilities		(6,108	)		(19,226	)
Accrued environmental liabilities		(86	)		(755	)
Other long-term liabilities		1			13,878

Net cash provided by operating activities		435,868			162,637

Cash flows from investing activities:
Capital expenditures		(105,159	)		(20,979	)
Proceeds from sale of assets		363			33
Insurance proceeds for UAN reactor rupture		—			225

Net cash used in investing activities		(104,796	)		(20,721	)

Cash flows from financing activities:
Principal payments on long-term debt		(115	)		(2,700	)
Payment of capital lease obligations		(452	)		(4,855	)
Payment of financing costs		(2,016	)		(10,498	)
Purchase of managing general partner interest and incentive distribution rights		—			(26,001	)
Proceeds from issuance of CVR Partners long-term debt		—			125,000
Proceeds from CVR Partners initial public offering, net of offering costs		—			325,136
Payment of treasury stock		—			(70	)
Exercise of stock options		413			—
Redemption of common units		(89	)		—
Excess tax benefit of share-based compensation		12			—
Distribution to CVR Partners' noncontrolling interest holders		(24,565	)		—

Net cash (used in) provided by financing activities		(26,812	)		406,012

Net cash increase in cash and cash equivalents		304,260			547,928
Cash and cash equivalents, beginning of period		388,328			200,049

Cash and cash equivalents, end of period	$	692,588		$	747,977

Supplemental disclosures
Cash paid for income taxes, net of refunds (received)	$	6,894		$	47,846
Cash paid for interest net of capitalized interest of $4,306 and $939 in 2012 and 2011, respectively	$	36,042		$	24,333
Non-cash investing and financing activities:
Accrual of construction in progress additions	$	(12,155	)	$	4,985

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(unaudited)

The "Company" or "CVR" are used in this report to refer to CVR Energy, Inc. and, unless the context otherwise requires, 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. In addition, the Company, through its majority-owned subsidiaries, owns the general partner and a majority of the common units of CVR Partners, LP, an independent producer and marketer of upgraded nitrogen fertilizer products in North America. The Company's operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

CVR's common stock is listed on the New York Stock Exchange under the symbol "CVI." On May 7, 2012, Carl C. Icahn and certain of his affiliates (collectively, "Icahn") announced that they had acquired control of CVR pursuant to a tender offer for all of the Company's common stock. As of June 30, 2012, Icahn owned approximately 82% of all outstanding shares. Prior to Icahn's acquisition, the Company was owned 100% by the public. See further discussion at Note 3 ("Change of Control").

As of December 31, 2010, approximately 40% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities ("GS" or "Goldman Sachs Funds") and Kelso Investment Associates VII, L.P. and related entities ("Kelso" or "Kelso Funds"). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interests in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering, whereby Kelso sold into the public market its remaining ownership interest in CVR Energy.

On December 15, 2011, CVR acquired all of the issued and outstanding shares of Gary-Williams Energy Corporation (subsequently converted to Gary-Williams Energy Company, LLC or "GWEC" and now known as Wynnewood Energy Company, LLC) for a preliminary purchase price of $592.3 million. In March 2012, the final purchase price was determined to be $593.4 million. The increase of $1.1 million was a result of further discussions and review of the working capital and the associated post closing statements. Assets acquired include a 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-owned storage tanks. See Note 4 ("Wynnewood Acquisition") for additional information regarding the Wynnewood Acquisition.

In conjunction with the consummation of CVR's initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF"), its nitrogen fertilizer business, to CVR Partners, LP, a Delaware limited partnership ("CVR Partners" or the "Partnership"), which at the time was 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). CVR concurrently sold the managing GP interest, including the associated incentive distribution rights ("IDRs"), to Coffeyville Acquisition III LLC ("CALLC III"), an entity owned by CVR's then

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

controlling stockholders and senior management, for $10.6 million. On April 13, 2011, the Partnership completed its initial public offering (the "Partnership IPO"), selling 22,080,000 common units at $16.00 per unit. The common units trade on the New York Stock Exchange under the symbol "UAN". In connection with the Partnership IPO, the IDRs were purchased by the Partnership for $26.0 million and subsequently extinguished. In addition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLC ("CRLLC"), a subsidiary of CVR for a nominal amount. The consideration for the IDRs was paid to the owners of CALLC III, which included the Goldman Sachs Funds, the Kelso Funds and members of CVR senior management. In connection with the Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market which represented an approximately 30% interest in the Partnership at the time of the Partnership IPO. The Company's noncontrolling interest reflected on the condensed consolidated balance sheet of CVR is impacted by the net income of, and distributions from, the Partnership.

At June 30, 2012, the Partnership had 73,043,356 common units outstanding, consisting of 22,123,356 common units owned by the public, representing approximately 30% of the total Partnership units, and 50,920,000 common units owned by CRLLC, representing approximately 70% of the total Partnership units. In addition, CRLLC owns 100% of the Partnership's general partner, CVR GP, LLC, which only holds a non-economic general partner interest.

In connection with the Partnership IPO, the Partnership's limited partner interests were converted into common units, the Partnership's special general partner interests were converted into common units, and the Partnership's special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing general partner sold its IDRs to the Partnership for $26.0 million, these interests were extinguished, and CALLC III sold the managing general partner to CRLLC for a nominal amount. As a result of the Partnership IPO, the Partnership has two types of partnership interests outstanding:

The Partnership has adopted a policy pursuant to which the Partnership will distribute all of the available cash it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter. The partnership agreement does not require that the Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Partnership can change the Partnership's distribution policy at any time.

The Partnership is operated by CVR's senior management (together with other officers of the general partner) pursuant to a services agreement among CVR, the general partner and the Partnership. The Partnership's general partner, CVR GP, LLC, manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by

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

CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the common unitholders and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Partnership. CVR, the Partnership, their respective subsidiaries and the general partner are parties to a number of agreements which regulate certain business relations between them. Certain of these agreements were amended in connection with the Partnership IPO.

On February 13, 2012, CVR announced its intention to sell a portion of its investment in the Partnership and use the proceeds to pay a special dividend to holders of its common stock and to strengthen the balance sheet. The Partnership filed a registration statement with the SEC on March 6, 2012, as amended on April 2, 2012. On May 15, 2012, the Partnership withdrew the registration statement.

The accompanying condensed consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries, including the Partnership and its subsidiary. All intercompany accounts and transactions have been eliminated in consolidation. The ownership interests of noncontrolling investors in its subsidiaries are recorded as noncontrolling interest. Certain prior year amounts have been reclassified to conform to current year presentation.

The Partnership is consolidated on the Company's financial statements based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR; and, therefore, CVR has the ability to control the activities of the Partnership. Additionally, the Partnership's general partner manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. The limited rights of the common unitholders of the Partnership are demonstrated by the fact that the common unitholders have no right to elect the general partner or the general partner's directors on an annual or other continuing basis. The general partner can only be removed by a vote of the holders of at least 66²/3% of the outstanding common units, including any common units owned by the general partner and its affiliates (including CRLLC, a wholly-owned subsidiary of CVR) voting together as a single class. Actions by the general partner that are made in its individual capacity will be made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The officers of the general partner manage the day-to-day affairs of the business. The majority of the officers of the general partner are also officers of CVR. Based upon the general partner's role and rights as afforded by the partnership agreement and the limited rights afforded to the limited partners, the condensed consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues and expenses of the Partnership.

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles ("GAAP") and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The condensed

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

consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries. The ownership interests of noncontrolling investors in its subsidiaries are recorded as a noncontrolling interest included as a separate component of equity for all periods presented. All intercompany account balances and transactions have been eliminated in consolidation. Certain information and footnotes required for complete financial statements under GAAP have been condensed or omitted pursuant to SEC rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2011 audited consolidated financial statements and notes thereto included in CVR's Annual Report on Form 10-K for the year ended December 31, 2011, which was filed with the SEC on February 29, 2012.

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 30, 2012 and December 31, 2011, the results of operations for the three and six months ended June 30, 2012 and 2011, comprehensive income for the three and six months ended June 30, 2012 and 2011, changes in equity for the six months ended June 30, 2012 and cash flows for the six months ended June 30, 2012 and 2011.

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 ended December 31, 2012 or any other interim period. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

The Company evaluated subsequent events, if any, that would require an adjustment or would require disclosure to the Company's condensed consolidated financial statements through the date of issuance of these condensed consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-04, "Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS," ("ASU 2011-04"). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards ("IFRS"). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. The provisions of ASU 2011-04 are effective for interim and annual periods beginning after December 15, 2011. The Company adopted this ASU as of January 1, 2012. The adoption of this standard did not impact the condensed consolidated financial statement footnote disclosures.

In June 2011, the FASB issued ASU No. 2011-05, "Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income," ("ASU 2011-05") which amends current comprehensive income

guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of stockholders' equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in ASU 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The Company adopted both ASUs as of January 1, 2012. The adoption of this standard expanded the Company's condensed consolidated financial statements and related footnote disclosures.

In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U.S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for interim and annual periods beginning January 1, 2013. The Company believes this standard will expand our condensed consolidated financial statement footnote disclosures.

On April 18, 2012, IEP Energy LLC ("IEP Energy"), a majority owned subsidiary of Icahn Enterprises, L.P. ("Icahn Enterprises"), and certain other affiliates of Icahn Enterprises and Carl C. Icahn (collectively, the "IEP Parties"), entered into a Transaction Agreement (the "Transaction Agreement") with CVR, with respect to IEP Energy's tender offer (the "Offer") to purchase all of the issued and outstanding shares of CVR's common stock for a price of $30 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent payment right for each share of CVR common stock (the "CCP"), which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR is executed on or prior to August 18, 2013 and such transaction closes.

The Offer expired on May 4, 2012. On May 7, 2012, the IEP Parties announced the results of the Offer. A total of 48,112,317 shares of CVR's common stock were validly tendered in the Offer. As all of the terms and conditions of the Offer had been satisfied, IEP Energy accepted for payment all of the tendered shares, which represented approximately 55% of the outstanding shares of CVR's common stock. Following the purchase of these shares, the IEP Parties owned approximately 70% of the outstanding shares of CVR's common stock. Subsequent to the expiration of the Offer on May 4, 2012, IEP Energy extended the Offer through May 18, 2012. As a result of the extension of the Offer and subsequent additional purchases of CVR's common stock by IEP Energy, the IEP Parties increased their ownership in CVR. As of June 30, 2012, IEP Energy owned approximately 82% of CVR's outstanding common stock.

Pursuant to the Transaction Agreement, for a period of 60 days CVR Energy solicited proposals or offers from third parties to acquire CVR Energy. The 60 day period began on May 24, 2012 and ended on July 23, 2012 without any qualifying offers.

Pursuant to the Transaction Agreement, all employee restricted stock awards ("awards") that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the appraised value of the shares at the time of vesting. Additional share-based compensation was incurred due to the modification of the awards and the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. See further discussion at Note 5 ("Share-Based Compensation").

On December 15, 2011, the Company completed the acquisition of all the issued and outstanding shares of GWEC, including its two wholly-owned subsidiaries (the "Wynnewood Acquisition") from The Gary-Williams Company, Inc. (the "Seller"). The preliminary purchase price of $592.3 million, as recorded at December 31, 2011, was increased by $1.1 million in March 2012 as a result of further discussions and review of the working capital and associated post closing statement provided to the Seller. The adjusted purchase price allocation resulted in immaterial differences to property, plant & equipment in the Condensed Consolidated Balance Sheet. The Company received settlement in the second quarter of 2012 of approximately $14.7 million associated with cash paid at closing for estimated working capital in excess of actual working capital.

For the three months and six months ended June 30, 2012, the Company incurred approximately $4.6 million and $8.3 million, respectively, of transaction fees and integration expenses that are included in selling, general and administrative expense in the Condensed Consolidated Statement of Operations. These costs primarily relate to accounting and other professional consulting fees incurred associated with post closing transaction matters and continued integration of various processes, policies, technologies and systems of GWEC.

Prior to CVR's initial public offering, CVR's subsidiaries were held and operated by Coffeyville Acquisition LLC ("CALLC"). Management of CVR held 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 Coffeyville Acquisition II LLC ("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. 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 and CALLC II account for share-based compensation in accordance with standards issued by the FASB regarding the treatment of share-based compensation, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. CVR was allocated non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.

In February 2011, CALLC and CALLC II sold 11,759,023 shares and 15,113,254 shares, respectively, of CVR's common stock pursuant to a registered public offering. In May 2011, CALLC sold 7,988,179 shares of CVR's common stock pursuant to a registered public offering.

As a result, CALLC and CALLC II ceased to be stockholders of the Company. Subsequent to CALLC II's divestiture of its ownership interest in the Company in February 2011 and CALLC's divestiture of its ownership interest in the Company in May 2011, no additional share-based compensation expense has been incurred with respect to override units and phantom units after each respective divestiture date. The final fair values of the override units of CALLC and CALLC II were derived based upon the values resulting from the proceeds received in connection with each entity's respective divestiture of its ownership in CVR. These values were utilized to determine the related compensation expense for the unvested units.

The final fair value of the CALLC III override units was derived based upon the value resulting from the proceeds received by the general partner upon the purchase of the IDR's by the Partnership. These proceeds were subsequently distributed to the owners of CALLC III which includes the override unitholders. This value was utilized to determine the related compensation expense for the unvested units. No additional share-based compensation has been or will be incurred with respect to override units of CALLC III subsequent to June 30, 2011 due to the complete distribution of the value prior to July 1, 2011.

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II and CALLC III.

Due to the divestiture of all ownership in CVR by CALLC and CALLC II and due to the purchase of the IDRs from the general partner and the distribution to CALLC III, there is no associated unrecognized compensation expense as of June 30, 2012.

CVR, through a wholly-owned subsidiary, has two Phantom Unit Appreciation Plans (the "Phantom Unit Plans") whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points has rights to receive distributions when holders of override operating units of CALLC and CALLC II receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units of CALLC and CALLC II receive distributions. There are no other rights or guarantees and the plans expire on July 25, 2015, or at the discretion of the compensation committee of the board of directors. In November 2010, CALLC and CALLC II sold common shares of CVR through a registered offering. As a result of this offering, the Company made a payment to phantom unit holders totaling approximately $3.6 million. In November 2009, CALLC II completed a sale of common shares of CVR through a registered offering. As a result of this sale, the Company made a payment to phantom unit holders totaling approximately $0.9 million. As described above, in February 2011, CALLC and CALLC II completed a sale of CVR common stock pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $20.1 million in the first quarter of 2011. As described above, in May 2011, CALLC completed an additional sale of CVR common stock pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $9.2 million in the second quarter of 2011. Due to the divestiture of all ownership of CVR by CALLC and CALLC II in 2011 and the associated payments to the holders of service and phantom performance points, there is no unrecognized compensation expense at June 30, 2012. Compensation expense for the three months ended June 30, 2012 and 2011 related to the Phantom Unit Plans was approximately $0.0 and $0.7 million, respectively. Compensation expense for the six months ended June 30, 2012 and 2011 related to the Phantom Unit Plans was approximately $0.0 and $10.6 million, respectively.

CVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights, non-vested shares, non-vested share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of June 30, 2012, only restricted shares of CVR common stock and stock options had been granted under the LTIP. Individuals who are eligible to receive awards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below.

In May 2012, all outstanding stock options equaling an equivalent of 22,900 common shares were exercised. No unexercised stock options remain as of the second quarter 2012.

A summary of restricted stock grant activity and changes during the six months ended June 30, 2012 is presented below:

Through the LTIP, restricted shares have been granted to employees of the Company. Prior to the change of control as discussed in Note 3, the restricted shares, when granted, were 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 stock. These shares generally vest over a three-year period.

The change of control and related Transaction Agreement discussed in Note 3 triggered a modification to the LTIP. Pursuant to the Transaction Agreement, all employee restricted stock awards that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the appraised value of the shares at the time of vesting. As a result of the modification, additional share-based compensation of approximately $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity awards to liability awards.

As of June 30, 2012, there was approximately $23.1 million of total unrecognized compensation cost related to restricted shares to be recognized over a weighted-average period of approximately two years. Compensation expense recorded for the three months ended June 30, 2012 and 2011 related to the restricted shares and stock options was approximately $17.3 million and $2.5 million, respectively. Compensation expense recorded for the six months ended June 30, 2012 and 2011 related to the restricted shares and stock options was approximately $20.8 million and $4.7 million, respectively.

In connection with the Partnership IPO, the board of directors of the general partner adopted the CVR Partners, LP Long-Term Incentive Plan ("CVR Partners LTIP"). Individuals who are eligible to receive awards under the CVR Partners LTIP include employees, officers, consultants and directors of CVR Partners and its general partner and their respective subsidiaries' parents. The CVR Partners

LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the CVR Partners LTIP is 5,000,000.

Through the CVR Partners LTIP, phantom and common units have been awarded to employees of the Partnership and the general partner. Units, when granted, are valued at the closing market price of CVR Partners' common units on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the award. These units generally vest over a three year period. As of June 30, 2012, there was approximately $2.2 million of total unrecognized compensation cost related to the units to be recognized over a weighted-average period of two years. Compensation expense recorded for the three months ended June 30, 2012 and 2011 related to the units was approximately $0.5 million and $0.3 million, respectively. Compensation expense recorded for the six months ended June 30, 2012 and 2011 related to the units was approximately $1.1 million and $0.3 million, respectively.

A summary of the Partnership's unit activity during the six months ended June 30, 2012 is presented below:

Capitalized interest recognized as a reduction in interest expense for the three months ended June 30, 2012 and 2011 totaled approximately $2.3 million and $0.8 million. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2012 and 2011 totaled approximately $4.3 million and $0.9 million. Land, building and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1 million and $0.3 million as of June 30, 2012 and 2011. Amortization of assets held under capital leases is included in depreciation expense.

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 approximately $0.9 million and $0.6 million for the three months ended June 30, 2012 and 2011, respectively. For the six months ended June 30, 2012 and 2011, cost of product sold excludes depreciation and amortization of approximately $1.6 million and $1.3 million, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately $30.7 million and $20.9 million for the three months ended June 30, 2012 and 2011, respectively. For the six months ended June 30, 2012 and 2011, direct operating expenses exclude depreciation and amortization of approximately $61.5 million and $41.8 million, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and costs associated with

maintaining the corporate and administrative office in Texas and the administrative offices in Kansas and Oklahoma. Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.6 million and $0.5 million for the three months ended June 30, 2012 and 2011, respectively. For the six months ended June 30, 2012 and 2011, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.2 million and $1.0 million, respectively.

The Company entered into an insurance premium finance agreement in November 2011 to finance a portion of the purchase of its 2011/2012 property insurance policies. The original balance of the note provided by the Company under such agreement was $9.9 million. The Company began to repay this note in equal installments commencing December 1, 2011. As of June 30, 2012 and December 31, 2011, the Company owed approximately $2.2 million and $8.8 million, respectively, related to this note.

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease had an initial lease term of one year with an option to renew for three additional one-year periods. During the second quarter of 2010, the Company renewed the lease for a one-year period commencing June 5, 2010. The Company had the option to purchase the property during the term of the lease, including the renewal periods. In March 2011, the Company exercised its purchase option and paid approximately $4.7 million to satisfy the lease obligation.

As a result of the Wynnewood Acquisition, the Company assumed two leases accounted for as capital leases related to the Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The two arrangements have remaining terms of 207 and 208 months, respectively. As of June 30, 2012, the outstanding obligation associated with these arrangements totaled approximately $52.8 million. See Note 13 ("Long-Term Debt") for additional information.

Total gross costs incurred as of June 30, 2012 due to the incident were approximately $11.5 million for repairs and maintenance and other associated costs. Approximately $0.0 and $0.2 million of these costs were recognized during the three months ended June 30, 2012 and 2011, respectively. Approximately $0.1 million and $0.6 million of these costs were recognized during the six months ended June 30, 2012 and 2011, respectively. The repairs and maintenance costs incurred are included in direct operating expenses (exclusive of depreciation and amortization). Of the gross costs incurred, approximately $4.5 million was capitalized in 2010, approximately $0.1 million was capitalized in 2011 and approximately $0.1 million was capitalized in 2012.

As of June 30, 2012, approximately $7.0 million of insurance proceeds have been received under the property damage insurance related to this incident. This amount was received prior to December 31, 2011. The recording of the insurance proceeds resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization) when received.

The 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 damage and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. Partial business interruption claims were filed during 2011 resulting in receipt of proceeds totaling $3.4 million for the year ended December 31, 2011. Of this amount, approximately $2.9 million was reported for the six months ended June 30, 2011. The proceeds associated with the business interruption claims are included on the Consolidated Statements of Operations under Insurance recovery—business interruption.

On December 28, 2010 the Coffeyville crude oil refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit ("FCCU"), which led to reduced crude oil throughput. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of December 31, 2011 were approximately $8.0 million. No costs have been recorded in 2012. The Company maintains property damage insurance policies which have an associated deductible of $2.5 million. The Company anticipates that substantially all of the costs in excess of the deductible should be covered by insurance. As of December 31, 2011, the Company had received $4.0 million of insurance proceeds and has recorded an insurance receivable related to the incident of approximately $1.2 million as of June 30, 2012. The insurance receivable is included in other current assets in the Condensed Consolidated Balance Sheet.

The Coffeyville crude oil refinery experienced a small fire at its continuous catalytic reformer ("CCR") in May 2011. Total gross repair and other costs related to the incident, as of June 30, 2012, were approximately $3.2 million. No costs have been recorded in 2012. The Company anticipates that substantially all of the costs in excess of the $2.5 million deductible should be covered by insurance under its property damage insurance policy. As of June 30, 2012, the Company has recorded an insurance receivable of approximately $0.7 million.

On May 19, 2012, CVR became a member of the consolidated federal tax group of American Entertainment Properties Corporation ("AEPC"), a wholly-owned subsidiary of Icahn Enterprises, and subsequently entered into a tax allocation agreement with AEPC (the "Tax Allocation Agreement"). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, that it would have paid if it were to file as a consolidated group separate and apart from AEPC.

As of June 30, 2012, the Company owes approximately $28.3 million for federal income taxes due to AEPC under the Tax Allocation Agreement, which is to be paid during the third quarter of 2012.

The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under ASC Topic 740—Income Taxes. As of June 30, 2012, the Company had unrecognized tax benefits of approximately $17.8 million, of which $0.2 million, if recognized, would impact the Company's effective tax rate. Unrecognized tax benefits that are not expected to be settled within the next twelve months are included in other long-term liabilities in the condensed consolidated balance sheet; unrecognized tax benefits that are expected to be settled within the next twelve months are included in income taxes payable. The Company has accrued interest of $0.1 million and no 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. At June 30, 2012, the Company's tax filings are generally open to examination in the United States for the tax years ended December 31, 2009 through December 31, 2011 and in various individual states for the tax years ended December 31, 2008 through December 31, 2011.

The Company's effective tax rate for the three and six months ended June 30, 2012 was 35.5% and 35.3%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.4%. The Company's effective tax rate for the three and six months ended June 30, 2012 is lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners, LP's earnings, as well as benefits for domestic production activities. The Company's effective tax rate for the three and six months ended June 30, 2011 was 36.4% and 36.6%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.7%. The Company's effective tax rate for the three and six months ended June 30, 2011 was lower than the statutory rate primarily due to the reduction of income subject

to tax associated with the noncontrolling ownership interest of CVR Partners' earnings, as well as benefits for domestic production activities.

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the "Issuers"), completed a private offering 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"). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Notes is amortized to interest expense and other financing costs over the respective term of the Notes. On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of approximately $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million. On May 16, 2011, CRLLC repurchased $2.7 million of the Notes at a purchase price of 103.0% of the outstanding principal amount, which resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized issue discount.

On December 15, 2011, the Issuers sold an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 ("New Notes"). The New Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of the New Notes is amortized to interest expense and other financing costs over the respective term of the New Notes. The New Notes were issued as "Additional Notes" pursuant to the indenture dated April 6, 2010 (the "Indenture") and, together with the existing first lien notes, are treated as a single class for all purposes under the Indenture including, without limitation, waivers, amendments, redemptions and other offers to purchase. Unless otherwise indicated, the New Notes and the existing first lien notes are collectively referred to herein as the "First Lien Notes."

The change of control discussed in Note 3 required CVR to make an offer to repurchase all of the Issuers' outstanding Notes; and on June 4, 2012, the Issuers offered to purchase all or any part of the Notes, at a cash purchase price of 101% of the aggregate principal amount of the Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Notes tendered.

The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year. At June 30, 2012, the estimated fair value of the First and Second Lien Notes was approximately $476.1 million and $248.4 million, respectively. These estimates of fair value are Level 2 as they were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC's subsidiaries other than the Partnership and CRNF.

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement ("ABL credit facility") with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility is scheduled to mature in August 2015 and replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility will be used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to additional lender commitments. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase the borrowings under the ABL credit facility to $400.0 million in the aggregate in connection with the New Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. As of June 30, 2012, CRLLC had availability under the ABL credit facility of $347.0 million and had letters of credit outstanding of approximately $53.0 million. There were no borrowings outstanding under the ABL credit facility as of June 30, 2012.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter's excess availability. The pricing for borrowings under the ABL credit facility can range from

LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

The ABL credit facility contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, the incurrence of liens on assets, and the ability to dispose of assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. The ABL credit facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. As of June 30, 2012, CRLLC was in compliance with the covenants contained in the ABL credit facility.

In connection with the ABL credit facility, CRLLC incurred lender and other third party costs of approximately $9.1 million for the year ended December 31, 2011. These costs will be deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the facility. In connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately $1.9 million, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.8 million of unamortized deferred financing costs associated with the first priority credit facility will continue to be amortized over the term of the ABL credit facility.

In connection with the closing of the Partnership's initial public offering in April 2011, the Partnership and CRNF were released as guarantors of the ABL credit facility.

In connection with the change in control described in Note 3 above, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the "ABL First Amendment"), pursuant to which the parties agreed to exclude Icahn's acquisition of Shares from the definition of change of control as provided in the ABL credit facility. Absent the ABL First Amendment, the change in control of CVR described above would have triggered an event of default pursuant to the ABL credit facility.

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million, with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at June 30, 2012. There is no scheduled amortization of the credit facility, which matures in April 2016. The carrying value of the Partnership's debt approximates fair value.

Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the credit facility is the

Eurodollar rate plus a margin of 3.50% or, for base rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership.

The credit facility requires the Partnership to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets and the ability of the Partnership to dispose of assets, to make restricted payments, investments and acquisitions, or enter into sale-leaseback transactions and affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility. As of June 30, 2012, CRNF was in compliance with the covenants contained in the credit facility.

In connection with the credit facility, the Partnership incurred lender and other third-party costs of approximately $4.8 million. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.

Basic and diluted earnings per share are computed by dividing net income attributable to CVR stockholders by the weighted-average number of shares of common stock outstanding. The components of the basic and diluted earnings per share calculation are as follows:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,

	2012		2011		2012		2011
	(in thousands, except share data)
Net income attributable to CVR Energy stockholders	$	154,734	$	124,865	$	129,532	$	170,653
Weighted-average number of shares of common stock outstanding		86,821,224		86,422,881		86,814,687		86,418,356
Effect of dilutive securities:
Non-vested common stock		1,629,790		1,362,167		1,645,254		1,364,131
Stock options		2,992		4,303		4,406		3,801

Weighted-average number of shares of common stock outstanding assuming dilution		88,454,006		87,789,351		88,464,347		87,786,288

Basic earnings per share	$	1.78	$	1.44	$	1.49	$	1.97
Diluted earnings per share	$	1.75	$	1.42	$	1.46	$	1.94

The minimum required payments for CVR's lease agreements and unconditional purchase obligations are as follows:

CVR leases various equipment, including rail cars, and real properties under long-term operating leases expiring at various dates. For the three months ended June 30, 2012 and 2011, lease expense totaled approximately $1.4 million and $1.3 million, respectively. For the six months ended June 30, 2012 and 2011, lease expense totaled approximately $2.7 million and $2.6 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR's option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. Additionally, in the normal course of business, the Company has long-term commitments to purchase oxygen, nitrogen, electricity, storage capacity and pipeline transportation services.

CVR Partners entered into a pet coke supply agreement with HollyFrontier Corporation which became effective on March 1, 2012. The initial term ends in 2013 and the agreement is subject to renewal.

From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, "Environmental, Health, and Safety ("EHS") Matters." Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and

adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. 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 any other litigation matters is not expected to have a material adverse effect on the accompanying condensed consolidated financial statements. There can be no assurance that management's beliefs or opinions with respect to liability for potential litigation matters are accurate.

Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, "Samson") filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs filed two lawsuits (the "Anstine and Arrow cases") against CRRM and other defendants in state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remained in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the Sem Group bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, "Sem"), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased from Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company ("J. Aron") and that J. Aron sold some of this crude oil to CRRM. All of the lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of the plaintiffs' alleged claims is unknown since the price and amount of crude oil sold by the plaintiffs and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, and J. Aron agreed to reimburse CRRM's prior attorney fees and out-of-pocket expenses in connection with the lawsuits. Samson and CRRM entered a stipulation of dismissal with respect to all of the Samson cases and the Samson cases were dismissed with prejudice on February 8, 2012. The dismissal does not pertain to the Anstine and Arrow cases.

On June 21, 2012, Goldman, Sachs & Co. ("GS") filed suit against CVR in state court in New York, alleging that CVR failed to pay GS approximately $18.5 million in fees allegedly due to GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock made by Carl C. Icahn and certain of his affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of June 30, 2012.

and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county's classification of its nitrogen fertilizer plant and has been disputing it before the Kansas Court of Tax Appeals, or COTA. However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2011, 2010, 2009 and 2008 and has estimated and accrued for property tax for the first six months of 2012. This property tax expense is reflected as a direct operating expense in our financial results. In January 2012, COTA issued a ruling indicating that the assessment in 2008 of CRNF's fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling and filed a petition for reconsideration with COTA (which was denied) and then filed an appeal to the Kansas Court of Appeals. CRNF is also appealing the valuation of the CRNF fertilizer plant for tax years 2009 through 2012, which cases remain pending before COTA. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid property tax expenses would be refunded to CRNF, which could have a material positive effect on our results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then CRNF expects that it will continue to pay property taxes at elevated rates.

On July 25, 2011, Mid-America Pipeline Company, LLC ("MAPL") filed an application with the Kansas Corporation Commission ("KCC") for the purpose of establishing rates ("New Rates") effective October 1, 2011 for pipeline transportation service on MAPL's liquids pipelines running between Conway, Kansas and Coffeyville, Kansas ("Inbound Line") and between Coffeyville, Kansas and El Dorado, Kansas ("Outbound Line"). CRRM currently ships refined fuels on the Outbound Line pursuant to transportation rates established by a pipeline capacity lease with MAPL which expired September 30, 2011 and CRRM currently ships natural gas liquids on the Inbound Line pursuant to a pipeage contract which also expired September 30, 2011. If MAPL were successful in obtaining the entirety of its proposed rate increase, under CRRM's historic pipeline usage patterns, the New Rates would result in a total annual increase of approximately $14.75 million for CRRM's use of the Inbound and the Outbound Lines. On September 30, 2011, the KCC issued an order continuing, on an interim basis, the existing rates for the Inbound Line and the Outbound Line from October 1, 2011 until the resolution of the matter. In addition, on September 21, 2011, MAPL filed an application with the U.S. Federal Energy Regulatory Commission ("FERC") for a rate increase on the Outbound Line with respect to shipments with an interstate destination. On October 28, 2011 FERC issued an order allowing MAPL to place its increased rate into effect October 1, 2011 with respect to interstate shipments, subject to refund based on the final outcome of the FERC proceedings. Historically, the majority of CRRM's shipments on the Outbound Line are to Kansas intrastate destinations and therefore, are subject to KCC and not FERC rate regulation. On April 3, 2012, the parties entered into a Settlement Agreement which resolved the rate dispute both at the KCC and at FERC. Among other provisions, the Settlement Agreement provides for pipeage contracts to be entered into between the parties with rates ("Settlement Rates") to be established for an initial one year period. The Settlement Rates consist of two components, a base rate and a pipeline integrity cost recovery rate along with an

annual take or pay minimum transportation quantity. The Settlement Rate on the Inbound Line was effective April 1, 2012 and the Settlement Rate on the Outbound Line was effective June 1, 2012. Prior to the end of the initial one year term of the pipeage contracts, and prior to the end of each annual period thereafter until the tenth anniversary of each of the two pipeage contracts, MAPL will provide its estimate of pipeline integrity costs for the upcoming annual period and CRRM may either agree to pay a rate for such upcoming annual period which includes a recovery rate component sufficient to collect such pipeline integrity costs for such upcoming annual period subject to true-up to actual costs at the end of the annual period. FERC rates will be the same as the KCC rates.

Crude oil was discharged from the Company's Coffeyville refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In connection with the discharge, the Company received in May 2008 notices of claims from sixteen private claimants under the Oil Pollution Act ("OPA") in an aggregate amount of approximately $4.4 million (plus punitive damages). In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita (the "Angleton Case"). In October 2009 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. The Company has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims except for one of the plaintiffs from the companion cases. The settlements did not have a material adverse effect on the condensed consolidated financial statements. The Company believes that the resolution of the remaining claim will not have a material adverse effect on the condensed consolidated financial statements.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the "Consent Order") with the U.S. Environmental Protection Agency (the "EPA") on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from the Company's Coffeyville refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company's refinery. The substantial majority of all required remedial actions were completed by January 31, 2009. The Company prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided the Company with a notice of completion indicating that the Company has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties.

On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the EPA seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard's claim for oversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking (i) recovery from CRRM of the EPA's oversight costs under the OPA, (ii) a civil penalty under

the Clean Water Act (as amended by the OPA) and (iii) recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"). (See "Environmental, Health and Safety ("EHS") Matters" below.) The Company has reached an agreement in principle with the DOJ to resolve the DOJ's claims. The Company anticipates that civil penalties associated with the proceeding will exceed $100,000; however, the Company does not anticipate that civil penalties or any other costs associated with the proceeding will be material. The discovery in the lawsuit is temporarily stayed while the parties attempt to finalize that agreement in a consent decree.

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company's environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants' reservations and defenses, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company's claims. The Company has received $25 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit.

The lawsuit with the insurance carriers under the environmental policies remains the only unsettled lawsuit with the insurance carriers related to these events.

CRRM, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Coffeyville Resources Terminal, LLC ("CRT"), and Wynnewood Refining Company, LLC ("WRC"), all of which are wholly-owned subsidiaries of CVR, and CRNF are 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.

CRRM, CRNF, CRCT, WRC and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may

be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the Oil Pollution Act of 1990 ("OPA") generally subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States.

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of June 30, 2012 and December 31, 2011, environmental accruals of approximately $1.8 million and $1.9 million, respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.4 million and $0.5 million, respectively, are included in other current liabilities. The Company's accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at June 30, 2012 and December 31, 2011, respectively. The accruals include estimated closure and post-closure costs of approximately $0.9 million and $0.9 million for two landfills at June 30, 2012 and December 31, 2011, respectively. The estimated future payments for these required obligations are as follows:

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.

CRRM, CRNF, CRCT, WRC and CRT are subject to extensive and frequently changing federal, state and local, environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, the storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. The ultimate impact on the Company's business of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws,

such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.

In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. With the change of control by Icahn Enterprises, the MSATII projects have been accelerated by three months due to the loss of Small Refiner status. Capital expenditures to comply with the rule are expected to be approximately $45.0 million for CRRM and $49.0 million for WRC.

CRRM's refinery is subject to the Renewable Fuel Standard ("RFS") which requires refiners to blend "renewable fuels" in with their transportation fuels or purchase renewable energy credits in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2011, about 8% of all fuel used was required to be "renewable fuel." For 2012, the EPA has proposed to raise the renewable fuel percentage standards to about 9%. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM's small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers ("RINs") in lieu of blending. To achieve compliance with the renewable fuel standard for the remainder of 2012, CRRM is able to blend a small amount of ethanol into gasoline sold at its refinery loading rack, but otherwise will have to purchase RINs to comply with the rule. CRRM requested "hardship relief" (an extension of the compliance deadline) from the EPA based on the disproportionate economic impact of the rule on CRRM, but the EPA denied CRRM's request on February 17, 2012.

WRC's refinery is a small refinery under the RFS and has received a two year extension of time to comply. Therefore, WRC will have to begin complying with the RFS beginning in 2013 unless a further extension is requested and granted.

The EPA is expected to propose "Tier 3" gasoline sulfur standards in 2012. If the EPA were to propose a standard at the level recently being discussed in the pre-proposal phase by the EPA, CRRM will need to make modifications to its equipment in order to meet the anticipated new standard. It is not anticipated that the Wynnewood refinery would require additional capital to meet the anticipated new standard. The Company does not believe that costs associated with the EPA's proposed Tier 3 rule will be material.

In March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior

ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed cleanup obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities. On June 30, 2009, CRRM submitted a force majeure notice to the EPA and KDHE in which CRRM indicated that it may be unable to meet the 2004 Consent Decree's January 1, 2011 deadline for the installation of controls on the FCCU to reduce emissions of sulfur dioxide and nitrogen oxides because of delays caused by the June/July 2007 flood. In February 2010, CRRM and the EPA agreed to a fifteen month extension of the January 1, 2011, deadline for the installation of FCCU controls which was approved by the Court as a "First Material Modification" to the 2004 Consent Decree. In the First Material Modification, CRRM agreed to offset any incremental emissions resulting from the delay by installing additional controls to existing emission sources over a set timeframe.

In March 2012, CRRM entered into a "Second Consent Decree" with the EPA, which replaces the 2004 Consent Decree (other than the RCRA provisions) and the First Material Modification. The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA identified industry-wide noncompliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into "global settlements" pertaining to all "marquee" issues. The 2004 Consent Decree covered some, but not all, of the "marquee" issues. The Second Consent Decree covers all of the marquee issues. Under the Second Consent Decree, the Company will be required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, the remaining costs of which are expected to be approximately $49.0 million, of which approximately $47.0 million is expected to be capital expenditures and complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree would not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the Court on April 19, 2012.

WRC's refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the "ODEQ") under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent

Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The costs of complying with the Wynnewood Consent Order, other than costs associated with a planned turnaround, are expected to be approximately $1.5 million. In consideration for entering into the Wynnewood Consent Order, WRC received a broad release from liability from ODEQ. The EPA may later request that WRC enter into a global settlement which, if WRC agreed to do so, would necessitate the payment of a civil penalty and the installation of additional controls.

On February 24, 2010, CRRM received a letter from the DOJ on behalf of the EPA seeking an approximately $0.9 million civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act ("EPCRA"). The Company has reached an agreement with EPA to resolve these claims. The resolution was included in the Second Consent Decree described above pursuant to which the Company has agreed to pay an immaterial civil penalty.

The EPA has investigated CRRM's operation for compliance with the Clean Air Act's RMP. On September 23, 2011, the DOJ, acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas (in addition to the matters described above, see "Flood, Crude Oil Discharge and Insurance") seeking recovery from CRRM related to alleged non-compliance with the RMP. The Company anticipates that civil penalties associated with the proceeding will exceed $100,000; however, the Company does not anticipate that civil penalties or any other costs associated with the proceeding will be material. The discovery in the lawsuit is temporarily stayed while the parties attempt to finalize that agreement in a consent decree.

From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company's compliance with the RMP and the release reporting requirements under CERCLA and the EPCRA. These previous investigations have resulted in the issuance of preliminary findings regarding CRNF's compliance status. In the fourth quarter of 2010, following CRNF's reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances), the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against the Company and the Company has not accrued for any liability associated with the investigations or releases.

WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the "CWA Consent Order"), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged noncompliance by WRC with its OPDES permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery's wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, we do not believe that the costs of the potential corrective actions would be material.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30, 2012 and 2011, capital expenditures were approximately $8.1 million and $0.9 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. For the six months ended June 30, 2012 and 2011, capital expenditures were approximately $11.0 million and $2.5 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

CRRM, CRNF, CRCT, WRC and CRT each 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 business, financial condition, or results of operations.

In accordance with ASC Topic 820—Fair Value Measurements and Disclosures ("ASC 820"), the Company utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

ASC 820 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:

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of June 30, 2012 and December 31, 2011:

	June 30, 2012

	Level 1		Level 2			Level 3		Total
	(in thousands)
Location and Description
Cash equivalents	$	178,508	$	—		$	—	$	178,508
Other current assets (marketable securities)		31		—			—		31
Other current assets (other derivative agreements)		—		6,862			—		6,862
Other long-term assets (other derivative agreements)		—		346			—		346

Total Assets	$	178,539	$	7,208		$	—	$	185,747

Other current liabilities (other derivative agreements)		—		(6,056	)		—		(6,056	)
Other current liabilities (interest rate swap)		—		(927	)		—		(927	)
Other long-term liabilities (other derivative agreements)		—		(1,214	)		—		(1,214	)
Other long-term liabilities (interest rate swap)		—		(1,957	)		—		(1,957	)

Total Liabilities	$	—	$	(10,154	)	$	—	$	(10,154	)

As of June 30, 2012 and December 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company's cash equivalents, available-for-sale marketable securities and derivative instruments. Additionally, the fair value of the Company's Notes is disclosed in Note 13 ("Long-Term Debt"). The Company's commodity derivative contracts are valued using broker quoted market prices of similar commodity contracts using Level 2 inputs. The Partnership has an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, net, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. The Company had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2012.

The Company's investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices.

CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Company from time to time enters into various commodity derivative transactions.

CVR has adopted accounting standards which impose 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 and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

CVR maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Condensed Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Condensed Consolidated Balance Sheets. Dependant upon the position of the open commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the Condensed Consolidated Balance Sheets. From time to time, CVR may be required to deposit additional funds into this margin account. The fair value of the open commodity positions as of June 30, 2012 was a net loss of $0.9 million included in accrued liabilities. For the three months ended June 30, 2012, the Company recognized a realized gain of $6.0 million and an unrealized loss of $1.9 million which is recorded in loss on derivatives, net in the Condensed Consolidated Statement of Operations. For the six months ended June 30, 2012, the Company recognized a realized loss of $2.2 million and an unrealized loss of $1.7 million which is recorded in loss on derivatives, net in the Condensed Consolidated Statement of Operations.

Beginning September 2011, the Company entered into several commodity swap contracts with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At June 30, 2012, the Company had open commodity hedging instruments consisting of 13.5 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at June 30, 2012 was a net asset of $0.9 million which was comprised of $5.1 million included in current liabilities, $1.2 million is included in long-term liabilities, $6.9 million is included in current assets and $0.3 million is included in long-term assets. For the three months ended June 30, 2012, the Company recognized a realized loss of $14.0 million and an unrealized gain of $48.7 million which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2012, the Company recognized a realized loss of $25.0 million and an unrealized loss of $79.6 million which are recorded in loss on derivatives, net in the Condensed Consolidated Statements of Operations.

On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commences on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At June 30, 2012, the effective rate was approximately 4.60%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) ("AOCI"), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense on the Condensed Consolidated Statement of Operations. The realized loss on the interest rate swap re-classed from AOCI into interest expense was $0.2 million and $0.5 million for the three and six months ended June 30, 2012, respectively.

On May 7, 2012, Carl C. Icahn and certain of his affiliates (collectively, "Icahn") announced that Icahn had acquired control of CVR pursuant to a tender offer to purchase all of the issued and outstanding shares of the Company's common stock. As of June 30, 2012, Icahn owned approximately 82% of all common shares outstanding.

Until February 2011, the Goldman Sachs Funds and Kelso Funds owned approximately 40% of CVR. On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold its remaining ownership interest in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering in which Kelso sold its remaining ownership interest in CVR. As a result of these sales, the Goldman Sachs Funds and Kelso Funds are no longer stockholders of the Company.

Since March 2009, the Company, through the Partnership, has leased 200 railcars from American Railcar Leasing LLC, a company controlled by Mr. Carl Icahn, the Company's majority stockholder. The agreement is scheduled to expire on March 31, 2014. For the three and six months ended June 30, 2012, $0.3 million and $0.5 million, respectively, of rent expense was recorded related to this agreement and is included in cost of product sold (exclusive of depreciation and amortization) in the Condensed Consolidated Statements of Operations.

As of June 30, 2012, the Company owes approximately $28.3 million for federal income taxes due to AEPC under the Tax Allocation Agreement, which is to be paid during the third quarter of 2012.

In connection with the Partnership IPO, an affiliate of GS received an underwriting fee of approximately $5.7 million for its role as a joint book-running manager. In April 2011, CRNF entered into a credit facility as discussed further in Note 13 ("Long-Term Debt") whereby an affiliate of GS was paid fees and expenses of approximately $2.0 million.

For the three and six months ended June 30, 2011, the Company recognized approximately $0.3 million and $0.5 million, respectively, in expenses for the benefit of GS, Kelso, the president and chief executive officer of CVR, in connection with CVR's Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees.

The Company measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR's two reporting segments, based on the definitions provided in ASC Topic 280—Segment Reporting. All operations of the segments are located within the United States.

Principal products of the Petroleum Segment are refined fuels, liquefied petroleum gas, asphalts, and petroleum refining by-products, including pet coke. The Petroleum Segment's Coffeyville refinery sells pet coke to the Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the Petroleum Segment, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by the Nitrogen Fertilizer Segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were approximately $2.4 million and $3.5 million for the three

months ended June 30, 2012 and 2011, respectively. Intercompany sales included in petroleum net sales were approximately $4.8 million and $4.9 million for the six months ended June 30, 2012 and 2011, respectively.

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) described below under "Nitrogen Fertilizer" for the three months ended June 30, 2012 and 2011 of approximately $(0.1 million) and $6.1 million, respectively. For the six months ended June 30, 2012 and 2011, the Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) of approximately $5.6 million and $5.3 million, respectively.

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $2.3 and $2.9 million for the three months ended June 30, 2012 and 2011, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $5.2 and $3.6 million for the six months ended June 30, 2012 and 2011, respectively.

Pursuant to the feedstock agreement, the Coffeyville refinery and nitrogen fertilizer plant have the right to transfer excess hydrogen (hydrogen determined not to be needed to meet the current anticipated operational requirements of the facility transferring the hydrogen) to one another. Sales of hydrogen to the Petroleum Segment have been reflected as net sales for the Nitrogen Fertilizer Segment. Receipts of hydrogen from the Petroleum Segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. For the three months ended June 30, 2012 and 2011, the net sales generated from intercompany hydrogen sales were $0.0 and $6.1 million, respectively. For the six months ended June 30, 2012 and 2011, the net sales generated from intercompany hydrogen sales were $5.7 million and $6.1 million, respectively. For the three months ended June 30, 2012 and 2011, the Nitrogen Fertilizer Segment also recognized approximately $0.1 million and $0.0, respectively, of cost of product sold related to the transfer of excess hydrogen. For the six months ended June 30, 2012 and 2011, the Nitrogen Fertilizer Segment also recognized approximately $0.1 million and $0.7 million, respectively, of cost of product sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.

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

The following table summarizes certain operating results and capital expenditures information by segment:

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2011			2012			2011
	(in thousands)
Net sales
Petroleum	$	2,229,539		$	1,376,681		$	4,128,024		$	2,487,941
Nitrogen Fertilizer		81,431			80,673			159,707			138,050
Intersegment elimination		(2,652	)		(9,638	)		(10,782	)		(11,010	)

Total	$	2,308,318		$	1,447,716		$	4,276,949		$	2,614,981

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,866,155		$	1,122,763		$	3,496,820		$	2,053,046
Nitrogen Fertilizer		10,725			9,746			23,323			17,237
Intersegment elimination		(2,670	)		(9,134	)		(10,778	)		(10,086	)

Total	$	1,874,210		$	1,123,375		$	3,509,365		$	2,060,197

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	71,583		$	44,054		$	164,286		$	89,464
Nitrogen Fertilizer		22,524			22,266			45,361			45,290
Other		(8	)		(113	)		(34	)		(113	)

Total	$	94,099		$	66,207		$	209,613		$	134,641

Insurance recovery—business interruption
Petroleum	$	—		$	—		$	—		$	—
Nitrogen Fertilizer		—			—			—			(2,870	)
Other		—			—			—			—

Total	$	—		$	—		$	—		$	(2,870	)

Depreciation and amortization
Petroleum	$	26,638		$	16,966		$	52,897		$	33,882
Nitrogen Fertilizer		5,158			4,648			10,596			9,285
Other		394			429			809			887

Total	$	32,190		$	22,043		$	64,302		$	44,054

Operating income (loss)
Petroleum	$	248,856		$	183,537		$	383,752		$	289,227
Nitrogen Fertilizer		36,047			39,346			67,473			56,112
Other		(49,131	)		(4,963	)		(74,945	)		(17,813	)

Total	$	235,772		$	217,920		$	376,280		$	327,526

Capital expenditures
Petroleum	$	26,990		$	8,626		$	62,393		$	13,214
Nitrogen fertilizer		16,944			4,006			39,218			6,047
Other		1,700			1,010			3,548			1,718

Total	$	45,634		$	13,642		$	105,159		$	20,979

On July 26, 2012, the Board of Directors of the Partnership's general partner declared a cash distribution for the second quarter of 2012 to the Partnership's unitholders of $0.60 per common unit. The cash distribution will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

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 condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, as well as our Annual Report on Form 10-K for the year ended December 31, 2011. Results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of results to be attained for any other period.

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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under "Risk Factors" in our Annual report on Form 10-K for the year ended December 31, 2011 in our Quarterly report on Form 10-Q for the quarter ended March 31, 2012 and this Quarterly report on Form 10-Q for the quarter ended June 30, 2012. Such factors includes, among others:

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

We are an independent petroleum refiner and marketer of high value transportation fuels in the mid-continental United States. In addition, we own the general partner and approximately 70% of the common units of CVR Partners, LP, a publicly-traded limited partnership that is an independent producer and marketer of upgraded nitrogen fertilizers in the form of ammonia and urea ammonia nitrate, or UAN.

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

Petroleum business. Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma. In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 40,000 bpd serving Kansas, Oklahoma, western Missouri, southwestern Nebraska and Texas, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and at throughput terminals on Magellan and NuStar Energy, LP's ("NuStar") refined products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of Company owned and leased pipeline) that transports crude oil to our Coffeyville refinery from its Broome Station tank farm and associated crude oil storage tanks with a capacity of 1.2 million barrels, (4) crude oil storage tanks with a capacity of 0.5 million barrels in Wynnewood, Oklahoma, (5) an additional 3.3 million barrels of leased storage capacity located in Cushing, Oklahoma and other locations and (6) 1.0 million barrels of company owned crude oil storage in Cushing, Oklahoma.

Our Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States and our Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations including Canada. The early June 2012 reversal of the Seaway Pipeline that now flows from Cushing, OK to the U. S. Gulf Coast has eliminated our ability to source foreign waterborne crude oil from around the world, as well as deepwater U.S. Gulf of Mexico produced sweet and sour crude oil grades. 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 Operating, L.P., and NuStar.

Crude oil is supplied to our Coffeyville refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead and Keystone pipelines (as discussed more fully in Note 15 to the financial statements) from Canada to Cushing. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our Coffeyville refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics. Our Wynnewood refinery is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and other U.S. domestically produced crude oils. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the second quarter of 2012 was $(2.06) per barrel compared to $(5.04) per barrel in the second quarter of 2011.

On July 10, 2012, CVR and the union representing approximately 65% of the employees at our Wynnewood refinery agreed to a new three-year collective bargaining agreement extending to June 2015.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Partnership. We own the general partner and approximately 70% of the common units of the Partnership. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility that is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day of hydrogen. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. In 2011, the nitrogen fertilizer business produced 411,189 tons of ammonia, of which approximately 72% was upgraded into 714,130 tons of UAN. For the three and six months ended June 30, 2012, the nitrogen fertilizer business

produced 108,898 and 198,178 tons of ammonia, respectively, of which approximately 68% and 70% was upgraded into 180,024 and 334,603 tons of UAN, respectively.

The Partnership's growth strategy includes expanding production of UAN and acquiring additional infrastructure and production assets. The Partnership is anticipating completion of its UAN expansion project designed to increase the UAN production capacity by 400,000 tons, or approximately 50%, per year by January 1, 2013.

The primary raw material feedstock utilized in the nitrogen fertilizer production process is pet coke, which is produced during the crude oil refining process. In contrast, substantially all of the nitrogen fertilizer business' competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been significantly less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. The nitrogen fertilizer business currently purchases most of its pet coke from CVR Energy pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. On average, during the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by CVR Energy's crude oil refinery in Coffeyville.

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with IEP Energy LLC (the "Offeror"), a majority owned subsidiary of Icahn Enterprises, L.P. ("Icahn Enterprises") and certain other affiliates of Icahn Enterprises, and Carl C. Icahn (collectively with the Offeror, the "Offeror Parties"). Pursuant to the Transaction Agreement, the Offeror offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock (the "Shares") for a price of $30 per Share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment ("CCP") right for each Share which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes.

On May 7, 2012, Offeror Parties announced that control of CVR Energy had been acquired through the Offer. As a result of Shares tendered into the Offer during the initial offering period, the subsequent offering period and subsequent additional purchases, the Offeror owned approximately 82.0% of the Shares of CVR Energy as of June 30, 2012.

Pursuant to the Transaction Agreement, all employee restricted stock awards ("awards") that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the appraised value of the shares at the time of vesting. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products

are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out ("FIFO") accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors' facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

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

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the West Canadian Select ("WCS") differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refineries is that prices

we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 basis.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the six months ended June 30, 2012, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $3.9 million.

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

Consistent, safe, and reliable operations at our refineries are key to our financial performance and results of operations. Unplanned downtime at our refineries 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 the needed maintenance, feedstock logistics and other factors. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. Our Coffeyville refinery completed the first phase of a two phase turnaround during the fourth quarter of 2011. The second phase began and was completed during the first quarter of 2012. The next turnaround for the Wynnewood refinery is scheduled for the fourth quarter of 2012.

Our Coffeyville refinery experienced an equipment malfunction and small fire in connection with its FCCU on December 28, 2010, which led to reduced crude oil throughput and repair cost approximately $2.2 million net of insurance receivable for the year ended 2011. We used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4.0 million in total. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. We estimate that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident.

Our Coffeyville refinery also experienced a small fire at its CCR in May 2011, which led to reduced crude oil throughput for the second quarter of 2011. Repair costs, net of the insurance receivable, recorded for the year ended December 31, 2011 approximated $2.5 million. The interruption adversely impacted the production of refined products for the second quarter of 2011.

In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock

and uses a minimal amount of natural gas as an energy source in its operations. As a result, volatile swings in natural gas prices have a minimal impact on its results of operations. Instead, our adjacent Coffeyville refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a long-term pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets. Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors' facilities, 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.

In addition, 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.

Natural gas is the most significant raw material required in our competitors' production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility. This pricing and volatility has a direct impact on our competitors' cost of producing nitrogen fertilizer. Over the last year, natural gas prices have significantly decreased.

In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of nitrogen fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs.

We and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to our out-of-region competitors in serving the U.S. farm belt agricultural market. In 2011, approximately 56% of the corn planted in the United States was grown within a $40/UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors' revenues is derived from the lower margin industrial market. Our location on Union Pacific's main line increases our transportation cost advantage by lowering the costs of bringing our products to customers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we do not currently incur any intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $25 per ton over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

The value of nitrogen fertilizer products is also an important consideration in understanding our results. For the three and six months ended June 30, 2012, we upgraded approximately 68% and 70%, respectively, of our ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

The nitrogen fertilizer business' largest raw material expense is pet coke, which it purchases from our petroleum business and third parties. In the three and six months ended June 30, 2012, the nitrogen fertilizer business spent approximately $4.1 million and $9.1 million, respectively, for pet coke,

which equaled an average cost per ton of $31 and $36, respectively. In the three and six months ended June 30, 2011, the nitrogen fertilizer business spent approximately $4.1 million and $6.0 million, respectively, for pet coke, which equaled an average cost per ton of $30 and $23, respectively.

The high fixed cost of the nitrogen fertilizer business' direct operating expense structure also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs averaged approximately 87% of direct operating expenses over the 24 months ended December 31, 2011. The average annual operating costs over the 24 months ended December 31, 2011 have approximated $86 million, of which substantially all are fixed in nature.

The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from our adjacent Coffeyville crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.

Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The next turnaround is currently scheduled for the fourth quarter of 2012.

In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership in October 2007, we entered into a number of agreements with the Partnership that govern the business relations among the Partnership, CVR Energy and its affiliates, and the general partner of the Partnership. In connection with the Partnership IPO, we amended and restated certain of the intercompany agreements and entered into several new agreements with the Partnership. These include the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; a services agreement, in which our management operates the nitrogen fertilizer business; a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; an easement agreement; an environmental agreement; and a lease agreement pursuant to which we lease office space and laboratory space to the Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

For the three months ended June 30, 2012 and 2011, the nitrogen fertilizer segment was charged approximately $2.5 million and $2.7 million, respectively, for management services. For the six months ended June 30, 2012 and 2011, the nitrogen fertilizer segment was charged approximately $5.0 million and $5.3 million, respectively, for management services.

On March 30, 2011, CRRM and Vitol Inc. ("Vitol") entered into a Crude Oil Supply Agreement (the "Vitol Agreement"). This agreement replaced the previous supply agreement between CRRM and Vitol dated December 2, 2008, as amended, which was terminated by Vitol and CRRM on March 30, 2011.

The Vitol Agreement provides that CRRM will continue to obtain all of the crude oil for CRRM's refinery through Vitol, other than the crude oil gathered by us from Kansas, Missouri, North Dakota, Oklahoma, Wyoming and all adjacent states. CRRM and Vitol will continue to work together to identify crude oil and pricing terms that meet CRRM's crude oil requirements. CRRM and/or Vitol will negotiate the costs of each barrel of crude oil that is purchased from third-party crude oil suppliers. Vitol purchases all such crude oil, executes all third-party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to CRRM. Title and risk of loss for all crude oil purchased by CRRM through the Vitol Agreement passes to CRRM upon delivery to the Company's Broome Station, located near Caney, Kansas. CRRM generally pays Vitol a fixed origination fee per barrel over the negotiated cost of each barrel purchased. The Vitol Agreement commenced March 30, 2011 and extends for an initial term ending December 31, 2013, but also allows for automatic renewal for successive one-year terms.

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.

In February 2012, Icahn commenced a tender offer to acquire all of the outstanding shares of common stock of our Company. On April 18, 2012, we entered into a transaction agreement and on May 7, 2012, Icahn announced that control of the Company had been acquired. CVR incurred related costs of approximately $29.4 million and $44.2 million for the three and six months ended June 30, 2012. We are currently challenging a majority of the expenses charged and, if we are successful, such expenses would be reversed and have a favorable impact to our results of operations.

The financial results of GWEC, which was acquired on December 15, 2011, have been included in the results of our petroleum business since the date of the Wynnewood Acquisition. The Wynnewood Acquisition enhances the petroleum business by expanding our process capacity and diversifying our asset base. Results for the three and six months ended June 30, 2012 included net sales of approximately $782.3 million and $1,607.8 million, respectively and net income of $94.9 million and $160.7 million, respectively, related to GWEC.

ABL Credit Facility. On February 22, 2011, we entered into a $250.0 million asset-backed revolving credit agreement ("ABL credit facility"). The ABL credit facility replaced the first priority credit facility described below, which was terminated. As a result of the termination of the first priority credit facility, we expensed a portion of our previously deferred financing costs of approximately $1.9 million. This expense is reflected on the Consolidated Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2011. On December 15, 2011, we entered into an incremental commitment agreement to increase availability under the ABL credit facility by an additional $150.0 million. In connection with entering into and then expanding the ABL credit facility, we incurred approximately $9.9 million of fees that were deferred and are to be amortized over the term of the credit facility on a straight-line basis.

Notes. In April 2010, we issued $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"). We used the proceeds from the sale of the Notes to pay off the $453.0 million of term loans as described below.

In December 2010, we made a voluntary unscheduled payment of $27.5 million on our First Lien Notes, resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million, which was recognized as a loss on extinguishment of debt in our Consolidated Statements of Operations.

On December 15, 2011, we issued an additional $200.0 million of our First Lien Notes to partially fund the Wynnewood Acquisition. Financing and other third party costs incurred at the time of $6.0 million were deferred and are amortized over the remaining term of the First Lien Notes. In connection with the Wynnewood Acquisition, in November 2011 we received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of the First Lien Notes. Fees and other third party costs related to the bridge commitment totaling $3.9 million were expensed in December 2011. We also recognized approximately $0.1 million of third party costs at the time the First Lien Notes were issued. Other financing and third party costs incurred at the time were deferred and are amortized over the respective terms of the First Lien Notes. The premiums paid, previously deferred financing costs subject to write-off and immediately recognized third party expenses are reflected as a loss on extinguishment of debt in our Consolidated Statements of Operations.

Partnership Credit Facility. On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the credit facility matures in April 2016. The average interest rate for the term loan for the six months ended June 30, 2012 was 3.94%. The revolving credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and other general needs of CRNF.

Through the Company's Long-Term Incentive Plan ("LTIP"), equity compensation awards may be awarded to the Company's employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by IEP Energy, LLC and the related change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy's common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement triggered a modification to the LTIP. Pursuant to the Transaction Agreement, all employee restricted stock awards that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the appraised value of the shares at the time of vesting. As a result of the modification, additional share-based compensation of $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. In addition, the classification changed from an equity award to a liability award due to the cash settlement of the awards. For the three months ended June 30, 2012 and 2011, we incurred compensation expense of $17.3 million and $2.5 million, respectively, related to non-vested share-based compensation awards. For the six months ended June 30, 2012 and 2011, we incurred compensation expense of $20.8 million and $4.7 million, respectively, related to non-vested share-based compensation awards.

Through the CVR Partners, LP Long-Term Incentive Plan, shares of non-vested common units may be awarded to the employees, officers, consultants, and directors of the Partnership, the general partner, and their respective subsidiaries and parents. Non-vested units, when granted, are valued at the closing market price of CVR Partners common units at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the three months ended June 30, 2012 and 2011, we incurred compensation expense of $0.5 million and $0.3 million, respectively, related to non-vested share-based compensation awards. For the six months ended June 30, 2012 and 2011, we incurred compensation expense of $1.1 million and $0.3 million, respectively, related to non-vested share-based compensation awards.

Through a wholly-owned subsidiary, we had two Phantom Unit Appreciation Plans (the "Phantom Unit Plans"), whereby directors, employees, and service providers historically could be awarded phantom points at the discretion of the board of directors or the compensation committee. We accounted for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC Topic 718, Compensation—Stock Compensation, the expense associated with these awards was based on the current fair value of the awards which was derived from a probability-weighted expected return method.

Also, in conjunction with our 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 this modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to recipients other than employees for acquiring or in conjunction with selling goods or services. In accordance with this accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. Certain override units became fully vested during the second quarter of 2010. As such, there was no additional expense incurred, subsequent to vesting, with respect to these share-based compensation awards. For the three months ended June 30, 2012 and 2011, we incurred compensation expense of $0.0 and a decrease of $0.8 million, respectively, as a result of the phantom and override unit share-based compensation awards. For the six months ended June 30, 2012 and 2011, we incurred compensation expense of $0.0 and $16.0 million, respectively, as a result of the phantom and override unit share-based compensation awards. Due to the divestiture of all ownership of CVR Energy by CALLC and CALLC II in 2011, there will be no further share-based compensation expense associated with override units subsequent to 2011. In association with the divestiture of ownership and the distributions to the override unitholders of CALLC and CALLC II, the holders of phantom units received the associated payments in 2011. As a result, there will be no further share-based compensation expense recorded for the Phantom Unit Plans subsequent to 2011.

Prior to the Partnership IPO, the noncontrolling interests represented the incentive distribution rights ("IDRs") of CVR GP, LLC. In April 2011, in connection with the Partnership IPO, the IDRs were purchased by the Partnership and were subsequently extinguished, eliminating the associated noncontrolling interest related to the IDRs. As a result of the Partnership IPO, CVR Energy recorded a noncontrolling interest for the common units sold into the public market, which represented an approximately 30% interest in the net book value of the Partnership at the time of the Partnership IPO. Effective with the Partnership IPO, CVR Energy's noncontrolling interest reflected on the consolidated balance sheet has been impacted by approximately 30% of the net income of the Partnership and related distributions for each future reporting period. The revenue and expenses from the Partnership are consolidated with CVR Energy's statement of operations because the general partner is owned by CRLLC, a wholly-owned

subsidiary of CVR Energy, and therefore has the ability to control the activities of the Partnership. However, the percentage of ownership held by the public unitholders is reflected as net income attributable to noncontrolling interest in our consolidated statement of operations and reduces consolidated net income to derive net income attributable to CVR Energy.

On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. The nitrogen fertilizer facility had previously scheduled a major turnaround to begin on October 5, 2010. To minimize disruption and impact to the production schedule, the turnaround was accelerated. The turnaround was completed on October 29, 2010 with the gasification and ammonia units in operation. The fertilizer facility restarted production of UAN on November 16, 2010. In addition to the adverse impact to UAN sales in the fourth quarter of 2010, the outage also resulted in delivery of lower priced tons being shifted from the fourth quarter of 2010 to the first and second quarters of 2011.

Total gross costs recorded as of June 30, 2012 due to the incident were approximately $11.5 million for repairs and maintenance and other associated costs. As of June 30, 2012, approximately $7.0 million of insurance proceeds have been received related to the property damage insurance claim. Of the costs incurred, approximately $4.7 million were capitalized. We also recognized income of approximately $3.4 million during 2011 from insurance proceeds received related to our business interruption insurance policy. Approximately $0.5 million was received during the third quarter of 2011, with the remainder received in March and April 2011.

CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF's nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county's classification of its nitrogen fertilizer plant and has been disputing it before the Kansas Court of Tax Appeals, or COTA. However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2011, 2010, 2009 and 2008 and has estimated and accrued for property tax for the first six months of 2012. This property tax expense is reflected as a direct operating expense in our financial results. In January 2012, COTA issued a ruling indicating that the assessment in 2008 of CRNF's fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling and filed a petition for reconsideration with COTA (which was denied) and has filed an appeal to the Kansas Court of Appeals. CRNF is also appealing the valuation of the CRNF fertilizer plant for tax years 2009 through 2011, which cases remain pending before COTA. CRNF has also appealed the 2012 valuation. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid property tax expenses would be refunded to CRNF, which could have a material positive effect on our results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then CRNF expects that it will continue to pay property taxes at elevated rates.

The current policy of the board of directors of the Partnership's general partner is to distribute all of the available cash the Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter. Available cash for each quarter will generally equal the Partnership's cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of its general partner deems necessary or appropriate. Additionally, the Partnership retains cash on hand associated with prepaid sales at each quarter end for future distributions to common unitholders based upon the recognition into income of the prepaid sales. The board of directors of the Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Partnership to make distributions at all.

On February 14, 2012, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on February 7, 2012 for the fourth quarter of 2011 in the amount of $0.588 per unit or $42.9 million in aggregate. We received $29.9 million in respect of our common units.

On May 15, 2012, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on May 8, 2012 for the first quarter of 2012 in the amount of $0.523 per unit or $38.2 million in aggregate. We received $26.6 million in respect of our common units.

On July 26, 2012, the board of directors of the Partnership's general partner declared a quarterly cash distribution to the Partnership's unitholders of $0.60 per unit or $43.8 million in aggregate. We will receive $30.6 million in respect of our common units. The cash distribution will be paid on August 14, 2012, to unitholders of record at the close of business on August 7, 2012. This distribution is for the second quarter of 2012.

Our and the Partnership's profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our and the Partnership's exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates the Partnership pays for the $125.0 million of term loan borrowings from a floating rate to a fixed rate.

On June 30 and July 1, 2011, CRNF entered into two Interest Rate Swap agreements with J. Aron. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. These Interest Rate Swap agreements commenced on August 12, 2011; therefore, no impact was recorded for the quarter ended June 30, 2011. The impact recorded for the three and six months ended June 30, 2012 was $0.2 million and $0.5 million in interest expense, respectively. For the three and six months ended June 30, 2012, the Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $0.7 million and $1.0 million, respectively.

Beginning in September 2011, we entered into commodity swap contracts with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. At June 30, 2012, we had open commodity hedging instruments consisting of 13.5 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production with effective periods beginning in 2012 and 2013. None of these swap contracts were designated as cash flow hedges and all changes in fair market value will be reported in earnings in the period in which the value change occurs.

Turnaround projects are a required standard procedure that involves the shut down and inspection of major process units in order to refurbish, repair and maintain the plant assets. These major maintenance projects occur every four to five years for our refineries and every two years for the nitrogen fertilizer plant.

The Coffeyville refinery completed the second phase of a two-phase planned turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery has incurred costs of approximately $21.0 million and $4.3 million for the six months ended June 30, 2012 and 2011, respectively, associated with the 2011/2012 turnaround. Costs associated with turnaround projects are recorded in direct operating expense (exclusive of depreciation and amortization) on the Consolidated Statements of Operations.

The Wynnewood refinery is scheduled to begin turnaround maintenance in the fourth quarter of 2012. We expect to incur approximately $100.0 million of expenses during 2012 related to the Wynnewood refinery's turnaround. The Wynnewood refinery has incurred $2.5 million of turnaround costs in the six months ended June 30, 2012. It is anticipated that the downtime associated with the Wynnewood refinery turnaround will approximate 40 to 45 days and will significantly impact our revenue for the fourth quarter of 2012.

The nitrogen fertilizer facility is scheduled to complete a major turnaround during the fourth quarter of 2012. The Partnership anticipates costs of approximately $5.0 million will be incurred during the fourth quarter of 2012 related to the turnaround. It is anticipated that the downtime associated with the nitrogen fertilizer turnaround will approximate 16 to 18 days and will significantly impact the Partnership's revenue for the fourth quarter of 2012.

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and six months ended June 30, 2012 and 2011. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in "Management's Discussion and Analysis of Financial Condition and Results of Operations," except for the balance sheet data as of December 31, 2011, is unaudited.

	Three Months Ended June 30,						Change from 2011

	2012			2011			Change			Percent
	(in millions, except per share amount)
Consolidated Statement of Operations Data:
Net sales	$	2,308.3		$	1,447.7		$	860.6			59.4	%
Cost of product sold(1)		1,874.2			1,123.4			750.8			66.8
Direct operating expenses(1)		94.1			66.2			27.9			42.1
Insurance recovery—business interruption		—			—			—			—
Selling, general and administrative expenses(1)		72.0			18.2			53.8			295.6
Depreciation and amortization(2)		32.2			22.0			10.2			46.4

Operating income		235.8			217.9			17.9			8.2
Interest expense and other financing costs		(19.0	)		(14.2	)		(4.8	)		33.8
Gain (loss) on derivatives, net
Realized		(8.1	)		0.5			(8.6	)		(1,720.0	)
Unrealized		46.9			6.4			40.5			632.8
Loss on extinguishment of debt		—			(0.2	)		0.2			—
Other income, net		0.8			0.5			0.3			60.0

Income before income tax expense		256.4			210.9			45.5			21.6
Income tax expense		91.1			76.7			14.4			18.8

Net income(3)		165.3			134.2			31.1			23.2
Less: Net income attributable to noncontrolling interest		10.6			9.3			1.3			14.0

Net income attributable to CVR Energy stockholders	$	154.7		$	124.9		$	29.8			23.9	%

Basic earnings per share	$	1.78		$	1.44		$	0.34			23.6	%
Diluted earnings per share	$	1.75		$	1.42		$	0.33			23.2	%
Weighted-average common shares outstanding:
Basic		86.8			86.4			0.4			0.5	%
Diluted		88.4			87.8			0.6			0.7	%

	Six Months Ended June 30,						Change from 2011

	2012			2011			Change			Percent
	(in millions, except per share amount)
Consolidated Statement of Operations Data:
Net sales	$	4,276.9		$	2,615.0		$	1,661.9			63.6	%
Cost of product sold(1)		3,509.4			2,060.2			1,449.2			70.3
Direct operating expenses(1)		209.6			134.6			75.0			55.7
Insurance recovery—business interruption		—			(2.9	)		2.9			—
Selling, general and administrative expenses(1)		117.3			51.5			65.8			127.8
Depreciation and amortization(2)		64.3			44.1			20.2			45.8

Operating income		376.3			327.5			48.8			14.9
Interest expense and other financing costs		(38.2	)		(27.4	)		(10.8	)		39.4
Gain (loss) on derivatives, net
Realized		(27.2	)		(18.4	)		(8.8	)		47.8
Unrealized		(81.3	)		3.2			(84.5	)		(2,640.6	)
Loss on extinguishment of debt		—			(2.1	)		2.1			—
Other income, net		1.1			1.1			—			—

Income before income tax expense		230.7			283.9			(53.2	)		(18.7	)
Income tax expense		81.4			103.9			(22.5	)		(21.7	)

Net income(3)		149.3			180.0			(30.7	)		(17.1	)
Less: Net income attributable to noncontrolling interest		19.8			9.3			10.5			112.9

Net income attributable to CVR Energy stockholders	$	129.5		$	170.7		$	(41.2	)		(24.1	)%

Basic earnings per share	$	1.49		$	1.97		$	(0.48	)		(24.4	)%
Diluted earnings per share	$	1.46		$	1.94		$	(0.48	)		(24.7	)%
Weighted-average common shares outstanding:
Basic		86.8			86.4			0.4			0.5	%
Diluted		88.5			87.8			0.7			0.8	%

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

	Three Months Ended June 30,				Six Months Ended June 30,

	2012		2011		2012		2011
	(unaudited) (in millions, except as otherwise indicated)
Consolidated Petroleum Segment Summary Financial Results
Net sales	$	2,229.5	$	1,376.7	$	4,128.0	$	2,487.9
Cost of product sold(1)		1,866.1		1,122.8		3,496.8		2,053.0
Direct operating expenses(1)(2)		69.1		44.0		140.8		89.5
Major scheduled turnaround expenses		2.5		—		23.5		—
Depreciation and amortization		26.6		17.0		52.9		33.9

Gross profit(3)		265.2		192.9		414.0		311.5
Plus direct operating expenses(1)		71.6		44.0		164.3		89.5
Plus depreciation and amortization		26.6		17.0		52.9		33.9

Refining margin(4)		363.4		253.9		631.2		434.9
Operating income (loss)	$	248.9	$	183.5	$	383.8	$	289.2
Adjusted Petroleum EBITDA(5)	$	381.4	$	208.4	$	535.2	$	296.6

	Three Months Ended June 30,								Six Months Ended June 30,

	2012				2011				2012				2011
			%				%				%				%
Refining Throughput and Production Data (barrels per day)
Throughput:
Sweet		148,912		74.6		84,654		72.6		129,781		73.1		82,302		74.1
Light/medium sour		20,488		10.3		198		0.2		22,728		12.8		397		0.4
Heavy sour		20,972		10.5		24,634		21.2		16,006		9.0		21,416		19.3

Total crude oil throughput		190,372		95.4		109,486		94.0		168,515		94.9		104,115		93.8
All other feedstocks and blendstocks		9,129		4.6		6,973		6.0		8,929		5.1		6,923		6.2

Total throughput		199,501		100.0		116,459		100.0		177,444		100.0		111,038		100.0

Production:
Gasoline		96,972		48.7		53,495		45.5		89,131		50.4		51,564		46.2
Distillate		82,075		41.3		48,959		41.6		72,202		40.9		45,934		41.1
Other (excluding internally produced fuel)		19,910		10.0		15,106		12.9		15,396		8.7		14,158		12.7

Total refining production (excluding internally produced fuel)		198,957		100.0		117,560		100.0		176,729		100.0		111,656		100.0

Product price (dollars per gallon):
Gasoline	$	2.89			$	3.07			$	2.88			$	2.86
Distillate	$	2.95			$	3.14			$	3.03			$	3.03

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2011			2012			2011
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	93.35		$	102.34		$	98.15		$	98.50
Crude Oil Differentials:
WTI less WTS (light/medium sour)		5.28			2.51			4.48			3.30
WTI less WCS (heavy sour)		20.45			17.61			23.79			19.76
NYMEX Crack Spreads:
Gasoline		30.42			27.85			27.95			22.98
Heating Oil		28.13			25.56			28.87			24.76
NYMEX 2-1-1 Crack Spread		29.27			26.71			28.41			23.87
PADD II Group 3 Basis:
Gasoline		(3.24	)		(1.59	)		(5.00	)		(1.82	)
Ultra Low Sulfur Diesel		2.16			3.24			0.28			2.21
PADD II Group 3 Product Crack:
Gasoline		27.18			26.26			22.95			21.16
Ultra Low Sulfur Diesel		30.29			28.81			29.14			26.97
PADD II Group 3 2-1-1		28.74			27.53			26.05			24.06

expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3): 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.
(4): 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 the performance of our refineries 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)) are taken directly from our Condensed 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 and refining margin per crude oil throughput barrel 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.
(5): Adjusted Petroleum EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, and where applicable, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, 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 segment for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,

	2012			2011		2012			2011
	(unaudited) (in millions)
Petroleum Consolidated:
Petroleum operating income	$	248.9		$	183.5	$	383.8		$	289.2
FIFO impacts (favorable), unfavorable(a)		105.4			4.1		95.0			(21.3	)
Share-based compensation		5.4			0.5		6.4			7.1
Major scheduled turnaround expenses(b)		2.5			1.1		23.5			4.3
Realized gain (loss) on derivatives, net		(8.1	)		0.5		(27.2	)		(18.4	)
Loss on disposition of fixed assets		—			1.5		—			1.5
Depreciation and amortization		26.6			17.0		52.9			33.9
Other income (expense)		0.7			0.2		0.8			0.3

Adjusted Petroleum EBITDA	$	381.4		$	208.4	$	535.2		$	296.6

	Three Months Ended June 30,				Six Months Ended June 30,

	2012		2011		2012		2011
	(unaudited) (in millions)
Coffeyville Refinery Financial Results
Net sales	$	2,162.2	$	1,376.6	$	3,457.9	$	2,487.7
Cost of product sold (exclusive of depreciation and amortization)		1,934.6		1,122.9		3,070.9		2,053.1
Direct operating expenses (exclusive of depreciation and amortization)		43.6		43.0		87.4		85.2
Major scheduled turnaround		0.9		1.1		21.0		4.3
Depreciation and amortization		17.4		16.3		34.7		32.6

Gross profit		165.7		193.3		243.9		312.5
Plus direct operating expenses (exclusive of depreciation and amortization)		44.5		44.1		108.4		89.5
Plus depreciation and amortization		17.4		16.3		34.7		32.6

Refining margin	$	227.6	$	253.7	$	387.0	$	434.6
Operating income	$	151.9	$	185.4	$	219.7	$	291.8

	Three Months Ended June 30,								Six Months Ended June 30,

	2012				2011				2012				2011
			%				%				%				%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Sweet		100,166		78.4		84,654		72.6		86,041		77.7		82,302		74.1
Light/medium sour		187		0.1		198		0.2		2,817		2.5		397		0.4
Heavy sour		20,972		16.4		24,634		21.2		16,006		14.4		21,415		19.3

Total crude oil throughput		121,325		94.9		109,486		94.0		104,864		94.6		104,114		93.8
All other feedstocks and blendstocks		6,500		5.1		6,973		6.0		5,934		5.4		6,923		6.2

Total throughput		127,825		100.0		116,459		100.0		110,798		100.0		111,037		100.0

Production:
Gasoline		62,351		47.9		53,495		45.5		56,310		50.1		51,564		46.2
Distillate		54,933		42.3		48,959		41.6		48,004		42.7		45,934		41.1
Other (excluding internally produced fuel)		12,753		9.8		15,106		12.9		8,123		7.2		14,157		12.7

Total refining production (excluding internally produced fuel)		130,037		100.0		117,560		100.0		112,437		100.0		111,655		100.0

Product price (dollars per gallon):
Gasoline	$	2.89			$	3.07			$	2.89			$	2.86
Distillate	$	2.94			$	3.14			$	3.00			$	3.03

	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012

	(unaudited) (in millions)
Wynnewood Refinery Financial Results
Net sales	$	782.3	$	1,607.8
Cost of product sold (exclusive of depreciation and amortization)		647.5		1,365.0
Direct operating expenses (exclusive of depreciation and amortization)		25.5		53.4
Major scheduled turnaround expense		1.6		2.5
Depreciation and amortization		8.4		16.7

Gross profit		99.3		170.2
Plus direct operating expenses (exclusive of depreciation and amortization)		27.1		55.9
Plus depreciation and amortization		8.4		16.7

Refining margin	$	134.8	$	242.8
Operating income	$	97.2	$	164.7

	Three Months Ended June 30, 2012				Six Months Ended June 30, 2012

			%				%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Sweet		48,745		68.0		43,740		65.6
Light/medium sour		20,301		28.3		19,911		29.9
Heavy sour		—		—		—		—

Total crude oil throughput		69,046		96.3		63,651		95.5
All other feedstocks and blendstocks		2,629		3.7		2,995		4.5

Total throughput		71,675		100.0		66,646		100.0

Production:
Gasoline		34,621		50.2		32,821		51.0
Distillate		27,142		39.4		24,198		37.6
Other (excluding internally produced fuel)		7,157		10.4		7,273		11.4

Total refining production (excluding internally produced fuel)		68,920		100.0		64,292		100.0

Product price (dollars per gallon):
Gasoline	$	2.88			$	2.90
Distillate	$	2.95			$	3.06

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

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2011			2012			2011
	(unaudited)
Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(3)		108.9			102.3			198.2			207.6
Ammonia (net available for sale)(3)		34.9			28.2			59.9			63.4
UAN		180.0			179.4			334.6			350.0
Pet coke consumed (thousand tons)		130.2			135.8			250.7			259.9
Pet coke (cost per ton)	$	31		$	30		$	36		$	23
Sales (thousand tons)(4):
Ammonia		29.4			33.6			59.3			60.9
UAN		177.2			166.1			335.5			345.4
Product pricing (plant gate) (dollars per ton)(4):
Ammonia	$	568		$	574		$	591		$	570
UAN	$	329		$	300		$	322		$	252
On-stream factor(5):
Gasification		99.2	%		99.3	%		96.2	%		99.6	%
Ammonia		98.0	%		98.5	%		94.7	%		97.6	%
UAN		96.7	%		97.6	%		90.1	%		95.4	%
Reconciliation of net sales (dollars in millions):
Sales net plant gate	$	75.1		$	69.2		$	142.9		$	121.8
Freight in revenue		6.3			5.4			11.1			10.2
Hydrogen revenue		—			6.1			5.7			6.1

Total net sales	$	81.4		$	80.7		$	159.7		$	138.1

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Net Sales. Consolidated net sales were $2,308.3 million for the three months ended June 30, 2012 compared to $1,447.7 million for the three months ended June 30, 2011. The increase of $860.6 million was due to an increase in petroleum net sales of approximately $852.8 million that resulted primarily from higher sales volume as a result of the acquisition of the Wynnewood refinery in December 2011. The increase in net sales as a result of increased volume was partially offset by a decrease in average sales prices of gasoline (down 5.7% to $2.89 per gallon) and distillate (down 6.1% to $2.95 per gallon) for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase in petroleum sales were coupled with an increase in nitrogen fertilizer net sales of $0.7 million, which was primarily due to higher average plant gate prices.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $1,874.2 million for the three months ended June 30, 2012 as compared to $1,123.4 million for the three months ended June 30, 2011. The increase of $750.8 million primarily resulted from an increase in throughput, which was partially offset by a decrease in crude oil prices. The increased crude oil throughput is a result of the inclusion of the Wynnewood refinery. Consumed crude oil cost per barrel decreased approximately 6.6% from an average price of $97.72 per barrel for the three months ended June 30, 2011 to an average price of $91.29 per barrel for the three months ended June 30, 2012. Additionally, the increase in cost of product sold (exclusive of depreciation and amortization) by the petroleum business was coupled with a slight increase of $1.0 million associated with the nitrogen fertilizer's third-party cost of product sold (exclusive of depreciation and amortization).

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $94.1 million for the three months ended June 30, 2012 as compared to $66.2 million for the three months ended June 30, 2011. This increase of $27.9 million was due to an increase in petroleum direct operating expenses of $27.6 million coupled with a small increase in nitrogen fertilizer direct operating expenses of approximately $0.1 million. The increase was primarily attributable to a full quarter's expenses for our Wynnewood refinery ($27.1 million), increases in labor ($1.0 million), operating supplies ($0.6 million) and other direct operating expenses ($0.1 million).

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $72.0 million for the three months ended June 30, 2012 as compared to $18.2 million for the three months ended June 30, 2011. This $53.8 million increase was primarily the result of higher payroll-related costs due to growth in staff, integration costs related to GWEC, overall higher costs associated with acquiring GWEC and costs incurred related to the tender offer and transaction agreement with certain entities affiliated with Carl Icahn.

Interest Expense. Consolidated interest expense for the three months ended June 30, 2012 was $19.0 million as compared to interest expense of $14.2 million for the three months ended June 30, 2011. This $4.8 million increase resulted primarily from higher interest cost due to the additional $200.0 million of Notes issued in December 2011 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Notes.

Realized Gain (loss) on Derivatives, net. For the three months ended June 30, 2012, we recorded an $8.1 million realized loss on derivatives compared to a $0.5 million realized gain on derivatives for the three months ended June 30, 2011. The change was primarily attributable to realized losses on our commodity swaps in the Petroleum segment. We entered several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011. For the three months ended June 30, 2012, the over-the-counter commodity swap positions resulted in a realized loss of $14.0 million, which was partially offset by a $6.0 million realized gain associated with other commodity derivative activities.

Unrealized Gain (loss) on Derivatives, net. For the three months ended June 30, 2012, we recorded a $46.9 million unrealized gain on derivatives compared to a $6.4 million unrealized gain on derivatives for the three months ended June 30, 2011. The change was primarily attributable to larger unrealized gains on our commodity swaps in the Petroleum segment. We entered several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011. For the three months ended June 30, 2012, the over-the-counter commodity swap positions resulted in an unrealized gain of $48.7 million, which was partially offset by a $1.9 million unrealized loss associated with other commodity derivative activities.

Income Tax Expense. Income tax for the three months ended June 30, 2012 was $91.1 million, or 35.5% of income before income tax expense, as compared to income tax expense of $76.7 million, or 36.4% of income before income tax expense, for the three months ended June 30, 2011. The Company's effective tax rate for the three months ended June 30, 2012 and 2011 is lower than the expected statutory rate of 39.4% primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners' earnings, as well as benefits for domestic production activities.

Net Sales. Petroleum net sales were $2,229.5 million for the three months ended June 30, 2012 compared to $1,376.7 million for the three months ended June 30, 2011. The increase of $852.8 million

was the result of significantly higher overall sales volume, which was partially offset by lower product prices. The higher sales volume is due to the inclusion of a full quarter's sales for our Wynnewood refinery for the three months ended June 30, 2012. Our average sales price per gallon for the three months ended June 30, 2012 for gasoline of $2.89 and distillate of $2.95 decreased by approximately 5.7% and 6.1%, respectively, as compared to the three months ended June 30, 2011.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $1,866.1 million for the three months ended June 30, 2012 compared to $1,122.8 million for the three months ended June 30, 2011. The increase of $743.3 million was primarily the result of an increase in crude oil throughputs, which was partially offset by a decrease in crude oil prices. The increase in crude oil throughputs is due to the inclusion of a full quarter's consumption at our Wynnewood refinery. Our average cost per barrel of crude oil consumed for the three months ended June 30, 2012 was $91.29 compared to $97.72 for the comparable period of 2011, a decrease of approximately 6.6%. Sales volume of refined fuels increased by approximately 74.6%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the three months ended June 30, 2012, we had an unfavorable FIFO inventory impact of $105.4 million compared to an unfavorable FIFO inventory impact of $4.1 million for the comparable period of 2011.

Refining margin per barrel of crude oil throughput decreased from $25.49 for the three months ended June 30, 2011 to $20.98 for the three months ended June 30, 2012. Refining margin adjusted for FIFO impact was $27.07 per crude oil throughput barrel for the three months ended June 30, 2012, as compared to $25.90 per crude oil throughput barrel for the three months ended June 30, 2011. Gross profit per barrel decreased to $15.31 for the three months ended June 30, 2012 as compared to gross profit per barrel of $19.36 in the equivalent period in 2011. The decrease of our refining margin per barrel is due to a decrease in the average sales prices of our produced gasoline and distillates, which was partially offset by a decrease in our cost of consumed crude oil. Our average sales price of gasoline decreased approximately 5.7% and our average sales price for distillates decreased approximately 6.1% for the three months ended June 30, 2012 over the comparable period of 2011. Consumed crude oil costs fell due to an 8.8% decrease in WTI for the three months ended June 30, 2012 over the three months ended June 30, 2011.

months ended June 30, 2011. The increase of $27.6 million was primarily the result of a full quarter's expenses for our Wynnewood refinery ($27.1 million) and increases at our Coffeyville refinery of expenses primarily related to labor ($1.0 million), operating supplies ($0.6 million) and other direct operating expenses ($0.1 million). Increases in direct operating expenses were partially offset by a decrease in repairs and maintenance ($1.3 million) at our Coffeyville refinery. Direct operating expenses per barrel of crude oil throughput for the three months ended June 30, 2012 decreased to $4.13 per barrel as compared to $4.42 per barrel for the three months ended June 30, 2011.

Nitrogen Fertilizer Business Results of Operations for the Three Months Ended June 30, 2012

Net Sales. Net sales were $81.4 million for the three months ended June 30, 2012 compared to $80.7 million for the three months ended June 30, 2011. For the three months ended June 30, 2012, ammonia and UAN made up $17.3 million and $64.1 million of our net sales, respectively. This compared to ammonia and UAN net sales of $19.8 million and $54.8 million for the three months ended June 30, 2011. The increase of $0.7 million was the result of higher average plant gate prices for UAN and increased sales unit volumes for UAN offset by lower hydrogen sales to Coffeyville's refinery and decreased sales unit volumes for ammonia. The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the quarter ended June 30, 2012 and June 30, 2011:

The increase in UAN sales volume for the three months ended June 30, 2012 compared to the three months ended June 30, 2011 was primarily attributable to an extended spring season for UAN application and additional corn acres planted. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units continue to demonstrate their reliability with the units reporting 99.2%, 98.0% and 96.7%, respectively, on-stream for the three months ended June 30, 2012. On-stream rates for the second quarter of 2011 were 99.3%, 98.5% and 97.6%, for the gasification, ammonia and UAN units, respectively.

Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer's designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or quarter-to-quarter. The plant gate price provides a measure that is consistently comparable period to period. Average plant gate prices for the three months ended June 30, 2012 were higher for UAN and lower for ammonia over the comparable period of 2011, increasing 9.6% and decreasing 1.0% respectively. The UAN price increase reflects strong farm belt market conditions.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold is primarily comprised of pet coke expense, freight expense and distribution expense. Cost of product sold for the three months ended June 30, 2012 was $10.7 million compared to $9.7 million for the three months ended June 30, 2011. The increase of $1.0 million is the result of higher third-party costs of

$1.4 million associated with higher freight costs, distribution costs and third-party coke costs partially offset by lower affiliate costs of $0.4 million associated with reduced coke volumes from Coffeyville's refinery.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses include costs associated with the actual operations of our plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) for the three months ended June 30, 2012 were $22.4 million as compared to $22.3 million for the three months ended June 30, 2011.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Net Sales. Consolidated net sales were $4,276.9 million for the six months ended June 30, 2012 compared to $2,615.0 million for the six months ended June 30, 2011. The increase of $1,661.9 million was due to an increase in petroleum net sales of approximately $1,640.1 million that resulted primarily from higher sales volume as a result of the acquisition of the Wynnewood refinery in December 2011. The increase in petroleum sales were coupled with an increase in nitrogen fertilizer net sales of $21.6 million which was primarily due to higher average plant gate prices.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,509.4 million for the six months ended June 30, 2012 as compared to $2,060.2 million for the six months ended June 30, 2011. The increase of $1,449.2 million primarily resulted from an increase in crude oil prices and throughput. The increased crude oil throughput is a result of the inclusion of the Wynnewood refinery. Consumed crude oil cost per barrel increased approximately 1.8% from an average price of $93.89 per barrel for the six months ended June 30, 2011 to an average price of $95.62 per barrel for the six months ended June 30, 2012. Additionally, the increase in cost of product sold (exclusive of depreciation and amortization) by the petroleum business was coupled with an increase of $6.1 million associated primarily with the nitrogen fertilizer's third-party cost of product sold (exclusive of depreciation and amortization).

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $209.6 million for the six months ended June 30, 2012 as compared to $134.6 million for the six months ended June 30, 2011. This increase was due to an increase in petroleum direct operating expenses of $74.8 million associated with an increase primarily attributable to a full quarter's expenses for our Wynnewood refinery ($55.9 million) and increases in expenses associated with turnaround ($19.2 million), offset by a decrease in other direct operating expenses ($0.1 million).

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $117.4 million for the six months ended June 30, 2012 as compared to $51.5 million for the six months ended June 30, 2011. This $65.9 million increase was primarily the result of higher payroll-related costs due to growth in staff, integration costs related to GWEC, overall higher costs associated with acquiring GWEC and costs incurred related to the tender offer and transaction agreement with certain entities affiliated with Carl Icahn.

Interest Expense. Consolidated interest expense for the six months ended June 30, 2012 was $38.2 million as compared to interest expense of $27.4 million for the six months ended June 30, 2011. This $10.8 million increase resulted primarily from higher interest cost due to the additional $200.0 million of Notes issued in December 2011 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Notes.

Realized Gain (loss) on Derivatives, net. For the six months ended June 30, 2012, we recorded a $27.1 million realized loss on derivatives compared to an $18.4 million realized loss on derivatives for the six months ended June 30, 2011. The change was primarily attributable to realized losses on our commodity swaps in the Petroleum segment. We entered several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011. For the six months ended June 30, 2012, the over-the-counter commodity swap positions resulted in a realized loss of $25.0 million. The remaining $2.1 million realized loss relates to other commodity derivative activities.

Unrealized Gain (loss) on Derivatives, net. For the six months ended June 30, 2012, we recorded a $81.3 million unrealized loss on derivatives compared to a $3.2 million unrealized gain on derivatives for the six months ended June 30, 2011. The change was primarily attributable to larger unrealized losses on our commodity swaps in the Petroleum segment. We entered several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011. For the six months ended June 30, 2012, the over-the-counter commodity swap positions resulted in an unrealized loss of $79.6 million. The remaining $1.7 million unrealized loss relates to other commodity derivative activities.

Income Tax Expense. Income tax expense for the six months ended June 30, 2012 was $81.4 million, or 35.3% of income before income tax expense, as compared to income tax expense of $103.9 million, or 36.6% of income before income tax expense, for the six months ended June 30, 2011. The Company's effective tax rate for the six months ended June 30, 2012 and 2011 is lower than the expected statutory rate of 39.4% primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners' earnings, as well as benefits for domestic production activities. The impact associated with the noncontrolling interest for the six months ended June 30, 2011 is less than 2012 due to noncontrolling ownership interest only having an impact beginning with and subsequent to the Partnership's IPO in April 2011.

Net Sales. Petroleum net sales were $4,128.0 million for the six months ended June 30, 2012 compared to $2,487.9 million for the six months ended June 30, 2011. The increase of $1,640.1 million was the result of higher overall sales volume. The higher sales volume is due to the inclusion of a full quarter's sales for our Wynnewood refinery for the six months ended June 30, 2012. Our average sales price per gallon for the six months ended June 30, 2012 was $2.88 for gasoline and $3.03 for distillate as compared to the six months ended June 30, 2011 average sales prices of $2.86 for gasoline and $3.03 for distillates.

primarily the result of an increase in crude oil throughputs and an increase in crude oil prices. The increase in crude oil throughputs is due to the inclusion of a full quarter's consumption at our Wynnewood refinery. Our average cost per barrel of crude oil consumed for the six months ended June 30, 2012 was $95.62 compared to $93.89 for the comparable period of 2011, an increase of approximately 1.8%. Sales volume of refined fuels increased by approximately 67.4%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the six months ended June 30, 2012, we had an unfavorable FIFO inventory impact of $95.0 million compared to a favorable FIFO inventory impact of $21.3 million for the comparable period of 2011.

Refining margin per barrel of crude oil throughput decreased from $23.08 for the six months ended June 30, 2011 to $20.58 for the six months ended June 30, 2012. Refining margin adjusted for FIFO impact was $23.68 per crude oil throughput barrel for the six months ended June 30, 2012, as compared to $21.95 per crude oil throughput barrel for the six months ended June 30, 2011. Gross profit per barrel decreased to $13.50 for the six months ended June 30, 2012 as compared to gross profit per barrel of $16.53 in the equivalent period in 2011. The decrease of our refining margin per barrel is due to an increase in our cost of consumed crude oil. Consumed crude oil costs increased 1.8% from $93.89 per crude oil barrel throughput for the six months ended June 30, 2011 to $95.62 per crude oil barrel throughput for the six months ended June 30, 2012.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $164.3 million for the six months ended June 30, 2012 compared to direct operating expenses of $89.5 million for the six months ended June 30, 2011. The increase of $74.8 million was primarily the result of a full quarter's expenses for our Wynnewood refinery ($55.9 million), and increases at our Coffeyville refinery of expenses primarily related with turnaround maintenance ($16.7 million), labor expense ($2.3 million), outside services ($1.2 million), catalyst and chemicals ($1.1 million), insurance ($0.9 million), operating supplies ($0.9 million) and other direct operating expenses ($0.3 million). Increases in direct operating expenses were partially offset by a decrease in repairs and maintenance ($4.5 million) at our Coffeyville refinery. Our Coffeyville refinery completed the second phase of its planned turnaround in March of 2012. Direct operating expenses per barrel of crude oil throughput for the six months ended June 30, 2012 increased to $5.36 per barrel as compared to $4.75 per barrel for the six months ended June 30, 2011.

Nitrogen Fertilizer Business Results of Operations for the Six Months Ended June 30, 2012

Net Sales. Net sales were $159.7 million for the six months ended June 30, 2012 compared to $138.1 million for the six months ended June 30, 2011. For the six months ended June 30, 2012, ammonia and UAN made up $36.0 million and $117.9 million of our net sales, respectively. This compared to ammonia and UAN net sales of $35.7 million and $96.3 million for the six months ended June 30, 2011. The increase of $21.6 million was the result of both higher average plant gate prices for both ammonia and UAN, offset by lower sales unit volumes for UAN and ammonia and reduced

hydrogen sales to Coffeyville's refinery. The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the quarter ended June 30, 2012 and June 30, 2011:

On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units continue to demonstrate their reliability with the units reporting 96.2%, 94.7% and 90.1%, respectively, on-stream for the six months ended June 30, 2012. On-stream rates for the six months ended June 30, 2011 were 99.6%, 97.6% and 95.4%, for the gasification, ammonia and UAN units, respectively. Lower on-stream factors were the result of downtime related to repairs for each of the units. This downtime resulted in decreased UAN production and related reduced sales volumes.

Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer's designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or quarter-to-quarter. The plant gate price provides a measure that is consistently comparable period to period. Average plant gate prices for the six months ended June 30, 2012 were higher for both ammonia and UAN over the comparable period of 2011, increasing 3.7% and 27.7% respectively. The price increases reflect strong farm belt market conditions.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold is primarily comprised of pet coke expense, freight expense and distribution expense. Cost of product sold for the six months ended June 30, 2012 was $23.3 million compared to $17.2 million for the six months ended June 30, 2011. The increase of $6.1 million is the result of higher affiliate costs of $1.2 million associated with higher prices and third-party costs of $4.9 million associated with increased volumes and higher prices.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses include costs associated with the actual operations of our plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) for the six months ended June 30, 2012 were $45.3 million as compared to $45.3 million for the six months ended June 30, 2011.

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

We believe that our cash flows from operations and existing cash and cash equivalents and improvements in our working capital, together with borrowings under our existing credit facilities as necessary, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control. Depending on the needs of our business contractual limitations and market conditions, we may from time to time seek to use equity securities, incur additional debt, modify the terms of our existing debt, issue debt securities, or otherwise refinance our existing debt. There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.

As of June 30, 2012, we had cash and cash equivalents of $692.6 million. As of June 30, 2012, we had no amounts outstanding and availability of $347.0 million under our ABL credit facility. Our availability under the ABL credit facility is reduced by outstanding letters of credit which, as of June 30, 2012 was $53.0 million. As of August 1, 2012, we had $373.4 million available under the ABL credit facility and CRNF had $25.0 million of availability under the credit facility. As of August 1, 2012, the Partnership had cash and cash equivalents of approximately $203.3 million and we had cash and cash equivalents (exclusive of the Partnership) of approximately $560.8 million.

The Partnership has a distribution policy in which it will generally distribute all of its available cash each quarter, within 45 days after the end of each quarter. The distributions will be made to all common unitholders. CRLLC currently holds approximately 70% of all common units outstanding. The amount of the distribution will be determined pursuant to the general partner's calculation of available cash for the applicable quarter. The general partner, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of the general partner's distribution policy, funds held by the Partnership will not be available for CRLLC's use, and CRLLC as a unitholder will receive its applicable percentage of the distribution of funds within 45 days following each quarter. The Partnership does not have a legal obligation to pay distributions and there is no guarantee that it will pay any distributions on the units in any quarter.

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the "Issuers"), completed the private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due April 1, 2015 (the "First Lien Notes") and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due April 1, 2017 (the "Second Lien Notes" and together with the First Lien Notes, the "Notes"). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, we made a voluntary unscheduled principal payment of $27.5 million on our First Lien Notes. As a result of this payment, we were required to pay a 3.0% premium totaling approximately $0.8 million. Additionally, an adjustment was made to our previously

deferred financing costs, underwriting discount and original issue discount of approximately $0.8 million. The premium payment and write-off of previously deferred financing costs, underwriting discount and original issue discount were recognized as a loss on extinguishment of debt. On May 16, 2011, we repurchased $2.7 million of the Notes at a purchase price of 103% of the outstanding principal amount, as discussed below in further detail. On December 15, 2011, we issued an additional $200.0 million of our 9.0% First Lien Senior Secured Notes to partially fund the Wynnewood Acquisition. The New Notes were issued at 105% of their principal amount. As of June 30, 2012, the Notes had an aggregate principal balance of $669.8 million and a net carrying value of $675.2 million.

The First Lien Notes were issued pursuant to an indenture (the "First Lien Notes Indenture"), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the "First Lien Notes Trustee"). The Second Lien Notes were issued pursuant to an indenture (the "Second Lien Notes Indenture" and together with the First Lien Notes Indenture, the "Indentures"), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the "Second Lien Notes Trustee" and in reference to the Indentures, the "Trustee"). The Notes are fully and unconditionally guaranteed by each of the Company's subsidiaries that also guarantee the ABL credit facility (the "Guarantors" and, together with the Issuers, the "Credit Parties"). The Partnership and CRNF do not guarantee the Notes.

The First Lien Notes bear interest at a rate of 9.0% per annum and mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes bear interest at a rate of 10.875% per annum and mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year, to holders of record at the close of business on March 15 and September 15, as the case may be, immediately preceding each such interest payment date.

On or after April 1, 2012, some or all of the First Lien Notes may be redeemed at a redemption price of (i) 106.750% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2012; (ii) 104.500% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; and (iii) 100% of the principal amount, if redeemed on or after April 1, 2014, in each case, plus any accrued and unpaid interest.

The Issuers have the right to redeem the Second Lien Notes at the redemption prices set forth below:

In the event of a "change of control" as defined in the Indentures, the Issuers are required to offer to buy back all of the Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of "all or substantially all of the assets of the Company" to any person other than permitted holders, (as defined in the

Indenture), (2) the liquidation or dissolution of CRLLC, (3) any person, other than a permitted holder, directly or indirectly acquiring 50% of the voting stock of CRLLC or (4) the first day when a majority of the directors of CRLLC or CVR Energy are not Continuing Directors (as defined in the Indentures). Continuing Directors are generally our existing directors and directors approved by the then-Continuing Directors.

The definition of "change of control" specifically excludes a transaction where CVR Energy becomes a subsidiary of another company, so long as (1) CVR Energy's stockholders own a majority of the surviving parent or (2) no one person owns a majority of the common stock of the surviving parent following the merger.

The Icahn change of control required the Issuers to make an offer to repurchase all of the Issuers' outstanding Notes. On June 4, 2012, the Issuers offered to purchase all or any part of the Notes, at a cash purchase price of 101.0% of the aggregate principal amount of the Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Notes tendered.

The Indentures also allow the Company to sell, spin-off or complete an initial public offering of the Partnership, as long as the Issuers offer to buy back a percentage of the Notes as described in the Indentures. In April 2011, the Partnership completed an initial public offering of common units. This offering triggered a Fertilizer Business Event (as defined in the Indentures). As a result, the Issuers were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer (as defined in the Indentures) was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes. Holders of $2.7 million of the Notes tendered their Notes to the Company. CRLLC repurchased the Notes in accordance with the terms of the tender offer.

The Indentures impose covenants that restrict the ability of the Credit Parties to (i) incur debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the Notes are rated investment grade by both S&P and Moody's. However, such covenants would be reinstituted if the Notes subsequently lost their investment grade rating. In addition, the Indentures contain customary events of default, the occurrence of which would result in, or permit the Trustee or holders of at least 25% of the First Lien Notes or Second Lien Notes to cause, the acceleration of the applicable Notes, in addition to the pursuit of other available remedies. We were in compliance with the covenants as of June 30, 2012.

The obligations of the Credit Parties under the Notes and the guarantees are secured by liens on substantially all of the Credit Parties' assets. The First Lien Notes are secured by first-priority liens on our fixed assets and a second priority lien on our inventory. The liens granted in connection with the Second Lien Notes rank junior to the liens in respect of the First Lien Notes.

CRLLC entered into a $250.0 million ABL credit facility on February 22, 2011, which was expanded to $400.0 million on December 15, 2011 in connection with the Wynnewood Acquisition. The ABL credit facility provides for borrowings, letter of credit issuances and a feature that permits an increase of borrowings up to an additional $100.0 million (in the aggregate) subject to additional lender commitments. The ABL credit facility is scheduled to mature in August 2015 and will be used to finance ongoing working capital, capital expenditures, letter of credit issuances and general needs of the Company and includes, among other things, a letter of credit sublimit equal to 90% of the total commitment. As of June 30, 2012, CRLLC had availability under the ABL credit facility of

$347.0 million and had letters of credit outstanding of approximately $53.0 million. There were no borrowings outstanding under the ABL credit facility as of June 30, 2012.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter's excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

Under its terms, the lenders under the ABL credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).

The ABL credit facility also contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, creation of liens on assets and the ability to dispose assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. The facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. We were in compliance with the covenants of the ABL credit facility as of June 30, 2012.

In connection with the Icahn change in control described above, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the "ABL First Amendment"), pursuant to which the parties agreed to exclude Icahn's acquisition of Shares from the definition of change of control as provided in the ABL Credit Agreement, dated as of February 22, 2011, by and among the parties thereto (the "ABL Credit Agreement"). Absent the ABL First Amendment, the change in control of the Company described above would have triggered an event of default pursuant to the ABL Credit Agreement.

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility (the "Partnership credit facility") with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The Partnership credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the Partnership credit facility matures in April 2016.

Borrowings under the Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the Partnership credit facility is the Eurodollar rate plus a margin of 3.50%, or for base rate loans, or the prime rate plus 2.50%. Under its terms, the lenders under the Partnership credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership and all of the capital stock of CRNF and each domestic subsidiary owned by the Partnership or CRNF. CRNF is the borrower under the Partnership credit facility. All obligations under the Partnership credit facility are unconditionally guaranteed by the Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to the Company and its direct subsidiaries.

As of June 30, 2012, no amounts were drawn under the Partnership's $25.0 million revolving credit facility.

The acquisition of common stock of CVR Energy by Carl Icahn and related entities and a change of control at CVR Energy did not trigger an event of default under the Partnership credit facility. However, an event of default will be triggered if CVR Energy or any of its subsidiaries (other than the Partnership and CRNF) terminates or violates any of its covenants in any of the intercompany agreements between the Partnership and CVR Energy and its subsidiaries (other than the Partnership and CRNF) and such action has a material adverse effect on the Partnership. If an event of default occurs, the administrative agent under the Partnership credit facility would be entitled to take various actions, including the acceleration of amounts due under the credit facility and all actions permitted to be taken by a secured creditor.

Our and the Partnership's profitability and cash flows are affected by changes in interest rates on our credit facility borrowings, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our and the Partnership's exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates we pay on our borrowings from a floating rate to a fixed interest rate.

On June 30 and July 1, 2011, the Partnership's CRNF subsidiary entered into two Interest Rate Swap agreements with J. Aron. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. These Interest Rate Swap agreements commenced on August 12, 2011. The impact recorded for the three and six months ended June 30, 2012 is $0.2 million and $0.5 million, respectively, in interest expense. For the three and six months ended June 30, 2012, the Partnership recorded losses of $0.5 million and $0.5 million, respectively, in fair market value on the Interest Rate Swap agreements. The combined fair market value of the interest rate swaps recorded in current and non-current liabilities is $(2.9) million. This amount is unrealized and included in accumulated other comprehensive income.

We divide our and the Partnership's capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.

The following table summarizes our total actual capital expenditures for the six months ended June 30, 2012 by operating segment and major category:

	Six Months Ended June 30, 2012

	(in millions)
Petroleum Business:
Coffeyville refinery:
Maintenance	$	27.5
Growth		1.8

Coffeyville refinery total capital excluding turnaround expenditures		29.3
Wynnewood refinery:
Maintenance		15.2
Growth		0.3

Wynnewood refinery total capital excluding turnaround expenditures		15.5
Other Petroleum:
Maintenance		3.8
Growth		13.8

Other petroleum total capital excluding turnaround expenditures		17.6

Petroleum business total capital excluding turnaround expenditures		62.4
Nitrogen Fertilizer Business (the Partnership):
Maintenance		1.6
Growth		37.6

Nitrogen fertilizer business total capital excluding turnaround expenditures		39.2

Corporate		3.6

Total capital spending	$	105.2

We expect the petroleum business to spend approximately $195.0 million to $200.0 million (not including capitalized interest) on capital expenditures in 2012. Of this amount $80.0 million to $85.0 million is expected to be spent for the Coffeyville refinery which includes approximately $80.0 million of maintenance capital. Approximately $80.0 million to $85.0 million is expected to be spent on capital for the Wynnewood refinery. Included in the petroleum business expected capital spend is approximately $15.0 million for further expansion of tank storage in Cushing, Oklahoma. We also expect to spend approximately $5.0 million associated with corporate related projects.

During the first quarter of 2012, the Coffeyville refinery completed the second phase of a planned two-phase turnaround. We incurred total major scheduled turnaround expenses of approximately $21.0 million in connection with the turnaround in 2012. The Wynnewood refinery is scheduled to begin turnaround maintenance in the fourth quarter of 2012. We expect to incur approximately $100.0 million of expenses during 2012 related to the Wynnewood refinery. Turnaround expenditures are not included in capital spending summarized above.

The nitrogen fertilizer business expects to spend $100.0 million to $110.0 million on capital expenditures in 2012, excluding capitalized interest. Of this amount, $10.0 million to $11.5 million will be spent on maintenance projects and $90.0 million to $100.0 million will be spent on growth projects including $70.0 million to $75.0 million on the UAN expansion project.

Using a portion of the proceeds of the Partnership's Initial Public Offering and term loan borrowings, the Partnership moved forward with the UAN expansion project, which will allow them the

flexibility to upgrade all of their ammonia production to UAN. Inclusive of capital spent prior to the Initial Public Offering, the Partnership now anticipates that the total capital spend associated with the UAN expansion will approximate $125.0 million (including capitalized interest). As of June 30, 2012, approximately $77.6 million had been spent, including $34.1 million which was spent during the six months ended June 30, 2012. It is anticipated that the UAN expansion will be completed by January 1, 2013.

In October 2011, the board of directors of the general partner of the Partnership approved a UAN terminal project that will include the construction of a two million gallon UAN storage tank and related truck and rail car load-out facilities that will be located in Phillipsburg, Kansas. The purpose of the UAN terminal is to distribute approximately 20,000 tons of UAN fertilizer annually. The expected cost of this project is approximately $2.0 million and completion is expected during the third quarter of 2012.

Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries or nitrogen fertilizer plant. Capital spending for the nitrogen fertilizer business has been and will be determined by the board of directors of the general partner of the Partnership.

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 cash flows used for operating activities for the six months ended June 30, 2012 was $435.9 million. The positive net cash flow used for operating activities was primarily driven by operating income of $376.2 million which was the result of higher operating margins. This positive operating income was coupled with a favorable change in trade working capital and other working capital. Trade working capital for the six months ended June 30, 2012 resulted in a cash in-flow of $63.1 million, primarily as a result of a decrease in accounts payable of $27.6 million coupled with a reduction of accounts receivable of $31.2 million and offset by an increase in inventory of $121.9 million. Other working capital activities of $66.7 million was primarily driven by an increase in current liabilities of $76.2 million partially offset by a decrease in prepaid expenses and other current assets of $9.5 million.

Net cash flows provided by operating activities for the six months ended June 30, 2011 was $162.6 million. The positive cash flow from operating activities generated over this period was primarily

driven by $180.0 million of net income before noncontrolling interest. This positive net income was primarily indicative of the operating margins for the period. Positive cash flows were impacted by an increase in trade working capital which resulted primarily from an increase in inventory driven by increased crude oil prices. 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 for trade working capital. The positive operating cash flow for the period was offset by unfavorable changes in trade working capital. Trade working capital for the six months ended June 30, 2011 resulted in a reduction of cash flows of $81.7 million which was primarily attributable to the increase in inventories ($68.8 million) and an increase in accounts receivable ($18.1 million), both of which were partially offset by an increase in accounts payable of $5.2 million. Other working capital activities resulted in net cash outflow of $24.7 million. Significant uses of cash for the six months ended June 30, 2011 included payments of income tax of approximately $47.8 million.

Net cash used in investing activities for the six months ended June 30, 2012 was $104.8 million compared to $20.7 million for the six months ended June 30, 2011. The increase in investing activities was primarily the result of an increase in capital expenditures of $105.2 million. The petroleum business' capital expenditures increased $62.4 million for the six months ended June 30, 2012 compared to the same period in 2011 primarily due to projects at the Coffeyville refinery, construction of crude oil storage in Cushing, Oklahoma capital spend incurred for the Wynnewood refinery. This increase was coupled with an increase of $39.2 million in nitrogen fertilizer capital expenditures primarily related to the UAN plant expansion.

Net cash used in financing activities for the six months ended June 30, 2012 was $26.8 million as compared to $406.0 million provided by financing activities for the six months ended June 30, 2011. During the six months ended June 30, 2012, we paid a cash distribution to noncontrolling interest holders of the Partnership totaling $24.6 million. Additionally, financing costs of approximately $2.0 million were paid during the period associated with increasing the borrowing capacity of the ABL credit facility and the issuance of additional notes in December 2011.

Net cash provided by financing activities for the six months ended June 30, 2011 was primarily attributable to the net proceeds received of $325.1 million from the Partnership IPO. Additionally, $125.0 million of proceeds was received by the Partnership from the issuance of long-term debt. These proceeds were partially offset by cash outflows of $26.0 million by the Partnership to purchase the managing general partner's incentive distribution rights. Financing costs were also paid during the period associated with the ABL credit facility and the credit facility of CRNF of approximately $10.5 million. We repurchased $2.7 million of our Notes in accordance with the terms of a tender offer associated with the Partnership IPO. During the first quarter of 2011, we also exercised our purchase option related to a corporate asset. This option resulted in a cash outflow of approximately $4.7 million and satisfied a capital lease obligation.

For the six months ended June 30, 2012, there were no borrowings or repayments under our ABL credit facility or Partnership credit facility. As of June 30, 2012, there were no short-term borrowings outstanding under our ABL credit facility.

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of June 30, 2012 relating to the Notes, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following June 30, 2012 and thereafter. As of June 30, 2012, there were no amounts outstanding under the ABL credit facility. The following table assumes no borrowings are made under the ABL credit facility.

	Payments Due by Period

	Total		2012		2013		2014		2015		2016		Thereafter
	(in millions)
Contractual Obligations
Long-term debt(1)	$	794.8	$	—	$	—	$	—	$	447.1	$	125.0	$	222.7
Operating leases(2)		40.1		5.1		9.1		7.1		5.6		4.7		8.5
Capital lease obligations(3)		51.7		0.2		1.0		1.1		1.2		1.4		46.8
Unconditional purchase obligations(4)		968.2		64.0		126.6		113.6		103.1		103.0		457.9
Environmental liabilities(5)		2.0		0.3		0.2		0.2		0.2		0.1		1.0
Interest payments(6)		202.4		32.2		24.2		64.5		44.9		24.2		12.4

Total	$	2,059.2	$	101.8	$	161.1	$	186.5	$	602.1	$	258.4	$	749.3
Other Commercial Commitments
Standby letters of credit(7)	$	53.0	$	—	$	—	$	—	$	—	$	—	$	—

(1): The Company issued the Notes in an aggregate principal amount of $500.0 million on April 6, 2010. The First Lien Notes and Second Lien Notes bear an interest rate of 9.0% and 10.875% per year, respectively, payable semi-annually. The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. In December 2010, we made a voluntary unscheduled prepayment on our First Lien Notes of $27.5 million. In May 2011, we repurchased $0.4 million of the First Lien Notes and $2.3 million of the Second Lien Notes. In December 2011 we issued an additional $200.0 million of First Lien Notes. As a result, the aggregate principal balance of the Notes is $669.8 million as of December 31, 2011, with $447.1 million (in respect of the First Lien Notes) due in 2015 and $222.7 million (in respect of the Second Lien Notes) due in 2017. The Partnership entered into a term loan facility in connection with its IPO in April 2011. The $125.0 million balance is due in 2016.
(2): The Partnership's nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods.
(3): The amount includes commitments under capital lease arrangements for equipment and for two leases associated with pipelines and storage and terminal equipment of GWEC.
(4): The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville, (c) a product supply agreement with Linde, (d) a pet coke supply agreement with HollyFrontier Corporation having an initial term that ends in 2013, subject to renewal and (e) approximately $497.8 million payable ratably over nine years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM would receive transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada's Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011.

(5): Environmental liabilities represent (a) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (b) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleaning and Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See "Commitments and Contingencies—Environmental, Health & Safety Matters."
(6): Interest payments are based on stated interest rates for the Notes. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year.
(7): Standby letters of credit issued against our ABL credit facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $52.7 million in letters of credit to secure transportation services for crude oil and a $0.1 million issued for the purpose of providing support during the transition of letters of credit assumed during the Wynnewood Acquisition.

We had no off-balance sheet arrangements as of June 30, 2012, as defined within the rules and regulations of the SEC.

In May 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-04, "Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS," ("ASU 2011-04"). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards ("IFRS"). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. The provisions of ASU 2011-04 are effective for interim and annual periods beginning after December 15, 2011. We adopted this ASU as of January 1, 2012. The adoption of this standard did not impact the condensed consolidated financial statement footnote disclosures.

In June 2011, the FASB issued ASU No. 2011-05, "Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income," ("ASU 2011-05") which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of stockholders' equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in ASU 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. We adopted both ASUs as of January 1, 2012. The adoption of this standard expanded the condensed consolidated financial statements and related footnote disclosures.

In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U.S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU

2011-11 will be effective for interim and annual periods beginning January 1, 2013. We believe this standard will expand our condensed consolidated financial statement footnote disclosures.

Our critical accounting policies are disclosed in the "Critical Accounting Policies" section of our Annual Report on Form 10-K for the year ended December 31, 2011. No modifications have been made to our critical accounting policies.

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 months ended June 30, 2012 does not differ materially from that discussed under Part II—Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2011. 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.

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 depends, 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.

At June 30, 2012, we had over-the-counter commodity swaps consisting of 13.5 million barrels of crack spreads primarily to fix the margin on a portion of future gasoline and distillate production from our two refineries. The fair value of the outstanding contracts at June 30, 2012 was a net unrealized gain of $0.9 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of the commodity hedging instruments of $13.5 million.

On June 30 and July 1, 2011 CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commenced on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At June 30, 2012, the effective rate was approximately 4.60%. The agreements were designated as cash flow hedges at

inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) ("AOCI"), and will be subsequently reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense.

The Partnership still has exposure to interest rate risk on 50% of its $125.0 million floating rate term debt. A 1.0% increase over the Eurodollar floor spread of 3.5%, as specified in the credit agreement, would increase interest cost to the Partnership by approximately $625,000 on an annualized basis, thus decreasing income from operations by the same amount.

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, evaluated as of June 30, 2012 the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, to ensure that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.

There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See Note 15 ("Commitments and Contingencies") to Part I, Item I of this Form 10-Q, which is incorporated by reference into this Part II, Item 1, for a description of the litigation, legal and administrative proceedings and environmental matters.

Other than with respect to the risk factors set for the below, there have been no material changes from the risk factors previously disclosed in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

Mr. Carl C. Icahn exerts significant influence over the Company and his interests may conflict with the interest of the Company's other stockholders.

Mr. Carl C. Icahn indirectly controls approximately 82% of the voting power of the Company's capital stock and, by virtue of such stock ownership, is able to control or exert substantial influence over the Company, including:

The existence of a controlling stockholder may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire a majority of the Company's outstanding common stock, which may adversely affect the market price of the stock.

Mr. Icahn's interests may not always be consistent with the Company's interests or with the interests of the Company's other stockholders. Mr. Icahn and entities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliates of Mr. Icahn. To the extent that conflicts of interest may arise between the Company and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner adverse to the Company or its other stockholders.

In addition, if Mr. Icahn were to sell, or otherwise transfer, some or all of his interests in us to an unrelated party or group, a change of control could be deemed to have occurred under the terms of the indentures governing senior notes, which would require us to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued interest to the date of repurchase, and the ABL Credit Facility, which would constitute an event of default under the ABL Credit Facility, which would allow our lenders to accelerate indebtedness owed to them. However, it is possible that we will not have sufficient funds at the time of the change of control to make the required repurchase of notes.

The Company's stock price may decline due to sales of shares by Mr. Carl C. Icahn:

Sales of substantial amounts of the Company's common stock, or the perception that these sales may occur, may adversely affect the price of the Company's common stock and impede its ability to raise capital through the issuance of equity securities in the future. Mr. Icahn could elect in the future

to request that the Company file a registration statement to enable him to sell shares of the Company's common stock. If Mr. Icahn were to sell a large number of shares into the public markets, Mr. Icahn could cause the price of the Company's common stock to decline.

We are a "controlled company" within the meaning of the New York Stock Exchange rules and, as a result, qualify for, and are relying on, exemptions from certain corporate governance requirements.

A company of which more than 50% of the voting power is held by an individual, a group or another company is a "controlled company" within the meaning of the New York Stock Exchange rules and may elect not to comply with certain corporate governance requirements of the New York Stock Exchange, including:

We are relying on all of these exemptions as a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the New York Stock Exchange.

		Exhibit Title

2.1	**	Transaction Agreement, dated as of April 18, 2012 among CVR Energy, Inc., IEP Energy LLC and each of the other Offeror Parties (as defined therein) (filed as Exhibit 2.1 to the Company's Current Report on Form 8-K, filed on April 23, 2012 and incorporated herein by reference).
10.1	*	First Amendment to Crude Oil Supply Agreement, dated as of April 24, 2012, between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC.
10.2	*	Second Amended and Restated Services Agreement, dated as of May 4, 2012, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc.
10.3	**	First Amendment to Credit Agreement, dated as of May 4, 2012, among Coffeyville Resources, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, the Holdings Companies (as defined therein), the Subsidiary Guarantors (as defined therein), certain other Subsidiaries of the Holding Companies or Coffeyville Resources, LLC from time to time party thereto, the lenders from time to time party thereto, Deutsche Bank Trust Company Americas, JPMorgan Chase Bank, N.A. and Wells Fargo Capital Finance, LLC, as Co-ABL Collateral Agents, and Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K, filed on May 11, 2012 and incorporated herein by reference).
10.4	*	Lease and Operating Agreement, dated as of May 4, 2012, between Coffeyville Resources Terminal, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
10.5	*	Memorandum of Understanding, dated as of May 4, 2012, between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
31.1	*	Certification of the Company's Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.

		Exhibit Title

31.2	*	Certification of the Company's Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.
32.1	*	Certification of the Company's Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	*	Certification of the Company's Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	*	The following financial information for CVR Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, filed with the SEC on August 2, 2012, formatted in XBRL ("Extensible Business Reporting Language") includes: (1) Condensed Consolidated Balance Sheets (unaudited), (2) Condensed Consolidated Statements of Operations (unaudited), (3) Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited), (4) Condensed Consolidated Statement of Changes in Equity (unaudited), (5) Condensed Consolidated Statements of Cash Flows (unaudited), (5) Condensed Consolidated Statement of Changes in Equity (unaudited) and (6) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail.***

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this quarterly report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company's public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.

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.


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .


Delaware		61-1512186
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2277 Plaza Drive, Suite 500 Sugar Land, Texas (Address of principal executive offices)		77479 (Zip Code)


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if smaller reporting company.)		Smaller reporting company o



Part I. Financial Information
Item 1.	Financial Statements	6
	Condensed Consolidated Balance Sheets—June 30, 2012 (unaudited) and December 31, 2011	6
	Condensed Consolidated Statements of Operations—Three and Six Months Ended June 30, 2012 and 2011 (unaudited)	7
	Condensed Consolidated Statements of Comprehensive Income—Three and Six Months Ended June 30, 2012 and 2011 (unaudited)	8
	Condensed Consolidated Statements of Changes in Equity—Six Months Ended June 30, 2012 (unaudited)	9
	Condensed Consolidated Statements of Cash Flows—Six Months Ended June 30, 2012 and 2011 (unaudited)	10
	Notes to the Condensed Consolidated Financial Statements—June 30, 2012 (unaudited)	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	88
Item 4.	Controls and Procedures	89
Part II. Other Information
Item 1.	Legal Proceedings	90
Item 1A.	Risk Factors	90
Item 6.	Exhibits	91
Signatures		93

Award Type	Benchmark Value (per Unit)			Grant Date	Compensation Expense Increase (Decrease) for the Three Months Ended June 30, 2011			Compensation Expense Increase (Decrease) for the Six Months Ended June 30, 2011

					(in thousands)
Override Value Units	$	11.31	1,839,265	June 2005	$	(27	)	$	4,960
Override Value Units	$	34.72	144,966	December 2006		(64	)		451
Override Units	$	10.00	642,219	February 2008		49			184

Total					$	(42	)	$	5,595

			Weighted- Average Grant-Date Fair Value

Non-vested at January 1, 2012	1,634,154		$	14.61
Granted	44,662			21.58
Vested	(85,349	)		10.92
Forfeited	(19,333	)		10.21

Non-vested at June 30, 2012	1,574,134		$	15.06

	Units			Weighted- Average Grant Date Fair Value

	(in thousands)
Non-vested at January 1, 2012		164,571		$	22.99
Granted		—			—
Vested		(16,887	)		19.74
Forfeited		—			—

Non-vested at June 30, 2012		147,684		$	23.36

	June 30, 2012		December 31, 2011

	(in thousands)
Finished goods	$	243,663	$	323,315
Raw materials and precious metals		194,478		157,931
In-process inventories		36,986		115,372
Parts and supplies		39,182		39,603

	$	514,309	$	636,221

	June 30, 2012		December 31, 2011

	(in thousands)
Land and improvements	$	27,674	$	26,136
Buildings		37,583		37,289
Machinery and equipment		2,013,055		1,967,269
Automotive equipment		10,618		10,217
Furniture and fixtures		12,844		12,349
Leasehold improvements		1,979		1,445
Railcars		2,496		2,496
Construction in progress		135,006		94,085

		2,241,255		2,151,286
Accumulated depreciation		539,950		478,325

	$	1,701,305	$	1,672,961

	June 30, 2012		December 31, 2011

	(in thousands)
Other derivative agreements (realized)	$	—	$	—
Other derivative agreements (unrealized)		6,056		—
Accrued interest		17,610		17,867
Partnership interest rate swap		927		905
Other liabilities		15,130		15,655

	$	39,723	$	34,427

	June 30, 2012		December 31, 2011

	(in thousands)
9.0% Senior Secured Notes, due 2015, net of unamortized premium of $7,377(1) and $9,003(2) as of June 30, 2012 and December 31, 2011, respectively	$	454,427	$	456,053
10.875% Senior Secured Notes, due 2017, net of unamortized discount of $2,004 and $2,159 as of June 30, 2012 and December 31, 2011, respectively		220,746		220,591
CRNF credit facility		125,000		125,000
Capital lease obligations		51,738		52,259

Long-term debt	$	851,911	$	853,903

	Operating Leases		Unconditional Purchase Obligations(1)

	(in thousands)
Six months ending December 31, 2012	$	5,065	$	63,994
Year ending December 31, 2013		9,093		126,619
Year ending December 31, 2014		7,145		113,593
Year ending December 31, 2015		5,586		103,115
Year ending December 31, 2016		4,664		103,013
Thereafter		8,563		457,896

	$	40,116	$	968,230

Year Ending December 31,	Amount

	(in thousands)
Six months ending December 31, 2012	$	281
2013		179
2014		162
2015		163
2016		106
Thereafter		1,059

Undiscounted total		1,950
Less amounts representing interest at 1.58%		198

Accrued environmental liabilities at June 30, 2012	$	1,752

	As of June 30, 2012		As of December 31, 2011

	(unaudited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	692.6	$	388.3
Working capital		904.5		769.2
Total assets		3,284.7		3,119.3
Long-term debt		851.9		853.9
Total CVR Energy stockholders' equity		1,276.5		1,151.6

	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012

	(unaudited) (dollars per barrel)
Wynnewood Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	21.47	$	20.97
Gross profit		15.82		14.70
Direct operating expenses (exclusive of depreciation and amortization)		4.30		4.83
Direct operating expenses per barrel sold		4.02		4.15
Barrels sold (barrels per day)		74,072		73,996

	Three Months Ended June 30, 2012						Three Months Ended June 30, 2011

													Total Variance
													Total Variance				Price Variance			Volume Variance
	Volume(1)		$ per barrel		Sales $(2)		Volume(1)		$ per barrel		Sales $(2)		Volume(1)		Sales $(2)		Price Variance			Volume Variance
																	(in millions)
Gasoline		9.7	$	121.49	$	1,178.3		5.3	$	128.87	$	690.9		4.3	$	478.4	$	(39.6	)	$	527.0
Distillate		7.6	$	124.00	$	946.9		4.5	$	132.03	$	599.3		3.1	$	347.6	$	(36.4	)	$	384.0

	Six Months Ended June 30, 2012						Six Months Ended June 30, 2011						Total Variance

	Volume(1)		$ per ton(2)		Sales $(3)		Volume(1)		$ per ton(2)		Sales $(3)		Volume(1)			Sales $(3)			Price Variance		Volume Variance
																			(in millions)
Ammonia		59,280	$	608	$	36.0		60,904	$	586	$	35.7		(1,624	)	$	0.4		$	1.3	$	(0.9	)
UAN		335,462	$	352	$	117.9		345,426	$	279	$	96.3		(9,964	)	$	21.6		$	25.1	$	(3.5	)
Hydrogen		562,657	$	10	$	5.7		630,497	$	10	$	6.1		(67,840	)	$	(0.4	)	$	0.3	$	(0.7	)


	CVR Energy, Inc.
August 2, 2012	By:	/s/ JOHN J. LIPINSKI Chief Executive Officer (Principal Executive Officer)
August 2, 2012	By:	/s/ FRANK A. PICI Chief Financial Officer (Principal Financial Officer)