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 April 30, 2013.

The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the three months ended March 31, 2013 (this "Report").

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.

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.

bpd—Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by 365 days, thus reflecting all operational and logistical limitations.

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

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.

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 during the refining process.

Group 3—A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include the Refining Partnership's Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and NCRA's refinery in McPherson, KS.

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.

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

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.

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.

rack sales—Sales which are made at terminals into third-party tanker trucks.

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

Refining Partnership IPO—The initial public offering of 27,600,000 (which includes the underwriters' subsequently-exercised option to purchase additional common units) common units representing limited partner interests of CVR Refining, LP (the "Refining Partnership"), which closed on January 23, 2013.

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.

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 the refineries and every two years for the nitrogen fertilizer plant.

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

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.

WEC—Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC.

WRC—Wynnewood Refining Company, LLC, the owner of the 70,000 bpd Wynnewood, Oklahoma refinery and related assets.

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.

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

	March 31, 2013			December 31, 2012

	(unaudited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,040,753		$	895,965
Accounts receivable, net of allowance for doubtful accounts of $2,303 and $1,999, respectively		283,212			210,579
Inventories		525,105			528,070
Prepaid expenses and other current assets		54,858			54,486
Insurance receivable		—			1,260
Income tax receivable		4,319			4,134
Deferred income taxes		16,968			57,423
Due from parent		—			9,162

Total current assets		1,925,215			1,761,079
Property, plant, and equipment, net of accumulated depreciation		1,782,644			1,782,918
Intangible assets, net		277			284
Goodwill		40,969			40,969
Deferred financing costs, net		13,070			16,639
Insurance receivable		4,042			4,042
Other long-term assets		5,842			4,964

Total assets	$	3,772,059		$	3,610,895

LIABILITIES AND EQUITY
Current liabilities:
Note payable and capital lease obligations	$	1,153		$	1,140
Accounts payable		378,612			440,113
Personnel accruals		40,339			51,154
Accrued taxes other than income taxes		41,340			36,693
Due to parent		57,214			—
Deferred revenue		28,604			965
Other current liabilities		94,733			95,566

Total current liabilities		641,995			625,631
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion		675,884			897,078
Accrued environmental liabilities, net of current portion		1,540			1,597
Deferred income taxes		510,998			386,940
Other long-term liabilities		44,235			39,511

Total long-term liabilities		1,232,657			1,325,126
Commitments and contingencies
Equity:
CVR stockholders' equity:
Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 issued as of March 31, 2013 and December 31, 2012		869			869
Additional paid-in-capital		811,947			582,287
Retained earnings		632,203			945,460
Treasury stock, 98,610 as of March 31, 2013 and December 31, 2012, at cost		(2,303	)		(2,303	)
Accumulated other comprehensive loss, net of tax		(1,063	)		(1,158	)

Total CVR stockholders' equity		1,441,653			1,525,155

Noncontrolling interest		455,754			134,983

Total equity		1,897,407			1,660,138

Total liabilities and equity	$	3,772,059		$	3,610,895

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,

	2013			2012
	(unaudited)
	(dollars in thousands, except per share data)
Net sales	$	2,352,419		$	1,968,631
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		1,813,582			1,635,155
Direct operating expenses (exclusive of depreciation and amortization)		108,548			115,514
Selling, general and administrative expenses (exclusive of depreciation and amortization)		28,429			45,342
Depreciation and amortization		34,198			32,112

Total operating costs and expenses		1,984,757			1,828,123

Operating income		367,662			140,508
Other income (expense):
Interest expense and other financing costs (Note 13)		(15,437	)		(19,253	)
Interest income		300			90
Realized loss on derivatives, net		(52,515	)		(19,086	)
Unrealized gain (loss) on derivatives, net		32,489			(128,167	)
Loss on extinguishment of debt		(26,127	)		—
Other income, net		116			117

Total other expense		(61,174	)		(166,299	)

Income (loss) before income tax expense		306,488			(25,791	)
Income tax expense (benefit)		93,743			(9,746	)

Net income (loss)		212,745			(16,045	)
Less: Net income attributable to noncontrolling interest		47,712			9,157

Net income (loss) attributable to CVR Energy Stockholders	$	165,033		$	(25,202	)

Basic earnings (loss) per share	$	1.90		$	(0.29	)
Diluted earnings (loss) per share	$	1.90		$	(0.29	)
Weighted-average common shares outstanding:
Basic		86,831,050			86,808,150
Diluted		86,831,050			86,808,150

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended March 31,

	2013			2012
	(unaudited)
	(in thousands)
Net income (loss)	$	212,745		$	(16,045	)
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $5 and $0		7			1
Change in fair value of interest rate swap, net of tax of $(13) and $(62)		(33	)		(173	)
Reclass of gain/loss to income on settlement of interest rate swap, net of tax of $71 and $61 (Note 13)		187			170

Total other comprehensive income (loss)		161			(2	)

Comprehensive income (loss)		212,906			(16,047	)
Less: Comprehensive income attributable to noncontrolling interest		47,778			9,156

Comprehensive income (loss) attributable to CVR stockholders	$	165,128		$	(25,203	)

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT 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, 2012		86,929,660	$	869	$	582,287	$	945,460		$	(2,303	)	$	(1,158	)	$	1,525,155		$	134,983		$	1,660,138
Impact from the issuance of CVR Refining's common units to the public		—		—		229,311		—			—			—			229,311			276,374			505,685
Dividend paid to CVR Energy stockholders		—		—		—		(477,571	)		—			—			(477,571	)		—			(477,571	)
Distributions to noncontrolling interest holders		—		—		—		—			—			—			—			(4,252	)		(4,252	)
Share-based compensation		—		—		349		(719	)		—			—			(370	)		871			501
Net income		—		—		—		165,033			—			—			165,033			47,712			212,745
Net unrealized gain on available-for-sale securities, net of tax		—		—		—		—			—			5			5			2			7
Net gain on interest rate swaps, net of tax		—		—		—		—			—			90			90			64			154

Balance at March 31, 2013		86,929,660	$	869	$	811,947	$	632,203		$	(2,303	)	$	(1,063	)	$	1,441,653		$	455,754		$	1,897,407

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,

	2013			2012
	(unaudited)
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	212,745		$	(16,045	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		34,198			32,112
Allowance for doubtful accounts		305			90
Amortization of deferred financing costs		747			1,910
Amortization of original issue discount		21			133
Amortization of original issue premium		—			(886	)
Deferred income taxes		21,397			(5,309	)
Loss on disposition of assets		34			566
Loss on extinguishment of debt		26,127			—
Share-based compensation		6,019			4,036
Unrealized (gain) loss on derivatives, net		(32,489	)		128,167
Changes in assets and liabilities:
Accounts receivable		(72,938	)		(63,521	)
Inventories		2,965			46,114
Prepaid expenses and other current assets		(3,168	)		(13,762	)
Insurance receivable		—			(4	)
Insurance proceeds on Coffeyville Refinery incident		1,260			—
Other long-term assets		(78	)		(114	)
Accounts payable		(32,073	)		49,797
Due to parent		66,376			—
Accrued income tax		(185	)		(4,924	)
Deferred revenue		27,639			7,003
Other current liabilities		19,470			21,184
Accrued environmental liabilities		(57	)		(96	)
Other long-term liabilities		(1	)		(112	)

Net cash provided by operating activities		278,314			186,339

Cash flows from investing activities:
Capital expenditures		(63,719	)		(59,525	)
Proceeds from sale of assets		36			149

Net cash used in investing activities		(63,683	)		(59,376	)

Cash flows from financing activities:
Payment of capital lease obligations		(271	)		(245	)
Payments on senior secured notes		(243,366	)		—
Payment of financing costs		(60	)		(1,142	)
Proceeds from CVR Refining's initial public offering, net of offering costs		655,677			—
Dividend to CVR Energy's stockholders		(477,571	)		—
Distribution to CVR Partners' noncontrolling interest holders		(4,252	)		(13,001	)

Net cash used in financing activities		(69,843	)		(14,388	)

Net increase in cash and cash equivalents		144,788			112,575
Cash and cash equivalents, beginning of period		895,965			388,328

Cash and cash equivalents, end of period	$	1,040,753		$	500,903

Supplemental disclosures:
Cash paid for income taxes, net of refunds	$	6,154		$	485
Cash paid for interest net of capitalized interest of $804 and $2,009 in 2013 and 2012, respectively	$	12,758		$	2,420
Non-cash investing and financing activities:
Accrual of construction in progress additions	$	(29,447	)	$	(8,253	)

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(unaudited)

The "Company" or "CVR" are used in this report to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries.

CVR is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of ammonia and UAN. The Company reports in two business segments: the petroleum segment (the operations of CVR Refining) and the nitrogen fertilizer segment (the operations of CVR Partners).

CVR's common stock is listed on the NYSE under the symbol "CVI." On May 7, 2012, IEP Energy, LLC and certain of its affiliates (collectively, "IEP") announced that they had acquired control of CVR pursuant to a tender offer for all of the Company's common stock (the "IEP Acquisition"). As of March 31, 2013, IEP owned approximately 82% of all outstanding shares. Prior to the IEP Acquisition, the Company was owned 100% by the public. Pursuant to the Transaction Agreement (the "Transaction Agreement") as a result of the IEP Acquisition, the settlement terms of all employee restricted share awards were modified. See further discussion in Note 3 ("Share-Based Compensation").

On April 13, 2011, the Nitrogen Fertilizer Partnership completed its initial public offering of 22,080,000 common units (the "Nitrogen Fertilizer Partnership IPO") priced at $16.00 per unit. The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol "UAN". In connection with the Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership at the time of the Nitrogen Fertilizer Partnership IPO. The Company's noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Nitrogen Fertilizer Partnership.

At March 31, 2013, the Nitrogen Fertilizer Partnership had 73,065,143 common units outstanding, consisting of 22,145,143 common units owned by the public, representing approximately 30% of the total Nitrogen Fertilizer Partnership units, and 50,920,000 common units owned by CRLLC, representing approximately 70% of the total Nitrogen Fertilizer Partnership units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer's Partnership's general partner, CVR GP, LLC, which only holds a non-economic general partner interest.

The Nitrogen Fertilizer Partnership has adopted a policy pursuant to which the Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership's general partner following the end of such quarter. The partnership agreement does not require that the

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

Nitrogen Fertilizer Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Nitrogen Fertilizer Partnership can change the Nitrogen Fertilizer Partnership's distribution policy at any time.

The Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership. The Nitrogen Fertilizer Partnership's general partner, CVR GP, LLC, manages the operations and activities of the Nitrogen Fertilizer 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 are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The members of the board of directors of the general partner are not elected by the common unitholders and are 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 Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Nitrogen Fertilizer Partnership IPO.

In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC ("CVR Refining Holdings"), which in turn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed the Refining Partnership, which issued them a 100% limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC ("Refining LLC") and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. ("Coffeyville Finance") to Refining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership in December 2012.

On January 23, 2013, the Refining Partnership completed its initial public offering of its common units representing limited partner interests (the "Refining Partnership IPO"). The Refining Partnership sold 24,000,000 common units at a price of $25.00 per unit. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per common unit. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." In connection with the Refining Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market which represented an approximate 19% interest in the Refining Partnership at the time of the Refining Partnership IPO. The Company's noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Refining Partnership. Prior to the Refining Partnership IPO, CVR owned 100% of the Refining Partnership and net income earned during this period was fully attributable to the Company.

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

At March 31, 2013, the Refining Partnership had 147,600,000 common units outstanding, consisting of 27,600,000 common units owned by the public (including 4,000,000 units owned by an Icahn affiliate), representing approximately 19% of the total Refining Partnership units, and 120,000,000 common units owned by CVR Refining Holdings, representing approximately 81% of the total Refining Partnership units. In addition, CVR Refining Holdings owns 100% of the Refining Partnership's general partner, CVR Refining GP, LLC, which only holds a non-economic general partner interest.

The Refining Partnership's general partner, CVR Refining GP, LLC, manages the Refining Partnership's activities subject to the terms and conditions specified in the Refining Partnership's partnership agreement. The Refining Partnership's general partner is owned by CVR Refining Holdings. The operations of its general partner, in its capacity as general partner are managed by its board of directors. Actions by its general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the Refining Partnership's general partner and not by the board of directors of its general partner. The members of the board of directors of the Refining Partnership's general partner are not elected by the Refining Partnership's unitholders and are 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 Refining Partnership.

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

The Refining Partnership entered into a services agreement on December 31, 2012, pursuant to which the Refining Partnership and its general partner obtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Refining Partnership is a controlled affiliate of CVR Energy, the Refining Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVR Partners, pursuant to which the Refining Partnership may not engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of the Nitrogen Fertilizer Partnership's outstanding units.

On March 29, 2013, the Refining Partnership filed a Registration Statement on Form S-1 to enable the offer and sale of common units, the proceeds of which would be used to redeem from CVR Refining Holdings an equal number of the Refining Partnership's common units.

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles ("GAAP") and in accordance with the

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

rules and regulations of the SEC. The condensed consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries including the Nitrogen Fertilizer Partnership and Refining Partnership and their 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, 2012 audited consolidated financial statements and notes thereto included in CVR's Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 14, 2013.

The Nitrogen Fertilizer Partnership and the Refining Partnership are both consolidated based upon the fact that their general partners are owned by CVR; and, therefore, CVR has the ability to control their activities. The Nitrogen Fertilizer Partnership's and the Refining Partnership's general partners manage their respective operations and activities subject to the terms and conditions specified in their respective partnership agreements. The operations of each general partner in its capacity as general partner are managed by its board of directors. The limited rights of the common unitholders of the Nitrogen Fertilizer Partnership and the Refining Partnership are demonstrated by the fact that the common unitholders have no right to elect either general partner or either general partner's directors on an annual or other continuing basis. Each 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 CVR) voting together as a single class. Actions by the general partner that are made in its individual capacity are made by the CVR subsidiary that serves 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 both general partners are also officers of CVR. Based upon the general partner's role and rights as afforded by the partnership agreements 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 Nitrogen Fertilizer Partnership and the Refining Partnership.

In the opinion of the Company's management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of March 31, 2013 and December 31, 2012 and the results of operations, comprehensive income and cash flows for the three months ended March 31, 2013 and 2012.

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, 2013 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.

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 GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities" ("ASU 2013-01"). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. The Company adopted these standards as of January 1, 2013. The adoption of these standards expanded the Company's condensed consolidated financial statement footnote disclosures.

In February 2013, the FASB issued ASU No. 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" ("ASU 2013-02"). ASU 2013-02 requires the Company to present information about reclassification adjustments from accumulated other comprehensive income in the financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification. The standard is effective for interim and annual periods beginning January 1, 2013 and is to be applied prospectively. The Company adopted this standard as of January 1, 2013. The adoption of this standard did not materially expand the Company's condensed consolidated financial statement footnote disclosures.

CVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of March 31, 2013, only grants of restricted stock units under the LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. The LTIP authorizes a share pool of 7,500,000 shares of the Company's common stock, 1,000,000 of which may be issued in respect of incentive stock options. A summary of the principal features of the LTIP is provided below.

A summary of restricted stock units grant activity and changes during the three months ended March 31, 2013 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 1, 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 in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. 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.

In December 2012, restricted stock units were granted to certain employees of CVR. The non-vested restricted stock units are expected to vest over three years on the basis of one-third of the award each year, with the exception of awards granted to certain executive officers that vest over one year. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company's common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company's common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.

Additionally, the Company approved a discretionary award of up to 62,920 restricted stock units to Mr. Lipinski, Chief Executive Officer and President of the Company, on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the Compensation Committee and approval of the board of directors of the Company, and is conditioned on Mr. Lipinski continuing to be employed by the Company through December 31, 2013. To the extent awarded, the

discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award.

As of March 31, 2013, there was approximately $16.6 million of total unrecognized compensation cost related to restricted stock units and associated dividends to be recognized over a weighted-average period of approximately one year. Total compensation expense for the three months ended March 31, 2013 and 2012 was approximately $5.4 million and $3.3 million, respectively, related to the LTIP. As of March 31, 2013 and December 31, 2012, the Company has a liability of $24.9 million and $19.5 million, respectively, for unvested restricted stock unit awards and associated dividends, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

In April 2011, the board of directors of CVR Partners' 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 (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of its general partner, and (3) members of the board of directors of its general partner. 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 Nitrogen Fertilizer Partnership and its general partner and to members of the board of directors of its general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. Prior to the amendment, the phantom units, when granted, were valued at the closing market price of the Nitrogen Fertilizer Partnership's common units on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the units. These units generally vest over a three-year period.

The amendment triggered a modification to the awards by providing the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to the amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award.

A summary of common units and phantom units (collectively "units") activity and changes under the CVR Partners LTIP during the three months ended March 31, 2013 is presented below:

As of March 31, 2013, there was approximately $3.0 million of total unrecognized compensation cost related to the units to be recognized over a weighted-average period of 1.36 years. Compensation expense recorded for each of the three months ended March 31, 2013 and 2012 related to the units was approximately $0.6 million. As of March 31, 2013 and December 31, 2012, the Company has a liability of $0.3 million and $0.2 million, respectively, for unvested phantom unit awards, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

In connection with the Refining Partnership IPO, on January 16, 2013, the board of directors of the general partner adopted the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIP include employees, officers, consultants and directors of CVR Refining and the general partner and their respective subsidiaries and parents. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. As of March 31, 2013, no awards have been granted under the plan.

Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of the first-in, first-out ("FIFO") cost or market for fertilizer products, refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

	March 31, 2013		December 31, 2012

	(in thousands)
Land and improvements	$	32,179	$	30,992
Buildings		41,349		40,617
Machinery and equipment		2,231,587		2,089,545
Automotive equipment		15,904		14,969
Furniture and fixtures		13,815		13,658
Leasehold improvements		2,483		2,483
Railcars		2,496		2,496
Construction in progress		77,907		189,291

		2,417,720		2,384,051
Accumulated depreciation		635,076		601,133

	$	1,782,644	$	1,782,918

Capitalized interest recognized as a reduction in interest expense for the three months ended March 31, 2013 and 2012 totaled approximately $0.8 million and $2.1 million. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1 million as of March 31, 2013 and December 31, 2012. 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 $1.2 million and $0.7 million for the three months ended March 31, 2013 and 2012, 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 $32.5 million and $30.8 million for the three months ended March 31, 2013 and 2012, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate and administrative office in Texas and the administrative offices in Kansas and Oklahoma. Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.5 million and $0.6 million for the three months ended March 31, 2013 and 2012, respectively.

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 March 31, 2013, the Company has recorded a liability of $57.2 million for federal income taxes due to AEPC under the Tax Allocation Agreement.

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 March 31, 2013, the Company had unrecognized tax benefits of approximately $41.1 million, of which $13.1 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 Sheets; 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 $1.1 million 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 March 31, 2013, 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, 2012 and in various individual states for the tax years ended December 31, 2008 through December 31, 2012.

The Company's effective tax rate for the three months ended March 31, 2013 was 30.6% as compared to the Company's combined federal and state expected statutory tax rate of 39.2%. The Company's effective tax rate for the three months ended March 31, 2013 is lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests of CVR Refining's and CVR Partners' earnings, as well as benefits for domestic production activities. The Company's effective tax rate for the three months ended March 31, 2012 was

37.8% 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 months ended March 31, 2012 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.

Prior to the Refining Partnership IPO, CVR's deferred taxes were recorded based upon each separate component of the book versus tax basis difference of CVR's assets and liabilities, including CVR Refining's assets and liabilities. Subsequent to the Refining Partnership IPO, deferred taxes related to the net book versus tax basis difference associated with the investment in CVR Refining are recorded as a noncurrent deferred tax liability.

On April 6, 2010, CRLLC and its then 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 "Old 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 Old Notes was amortized to interest expense and other financing costs over their respective terms. In addition, CRLLC incurred additional third-party fees and expenses totaling $3.6 million associated with the offering.

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 ("Additional First Lien Notes"). The Additional First Lien 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 $10.0 million for the Additional First Lien Notes was amortized to interest expense and other financing costs over the term of the Additional First Lien Notes. In conjunction with the issuance of the Additional First Lien Notes, CRLLC expanded the existing ABL credit facility (see "ABL Credit Facility" below for further discussion of the expansion and

associated accounting treatment) and incurred a commitment fee and other third-party costs associated with the expansion.

The related original issue premium and other debt issuance costs related to the Additional First Lien Notes were amortized over the remaining term of the First Lien Notes. Fees and third-party costs associated with the ABL credit facility expansion were amortized over the remaining term of the facility.

The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See further discussion below related to the tender for and subsequent redemption of all the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the three months ended March 31, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full. The 2022 Notes are guaranteed by the Refining Partnership, Refining LLC and its existing domestic subsidiaries. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR, the Nitrogen Fertilizer Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF"), a wholly-owned subsidiary of the Nitrogen Fertilizer Partnership, are not guarantors.

A portion of the net proceeds from the offering of the 2022 Notes approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. CRLLC used the remaining proceeds from the offering to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of the repayment of the First Lien Notes, a loss on extinguishment of debt of $33.4 million was recorded in the fourth quarter of 2012, which included the total premiums paid of $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million.

The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.

The 2022 Notes requires the Refining Partnership to maintain a minimum fixed charge coverage 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, the ability to dispose of assets, the ability to make payments on subordinated or unsecured debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Refining Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the fixed coverage ratio and there is no default or event of default under the 2022 Notes. As of March 31, 2013, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.

At March 31, 2013, the estimated fair value of the 2022 Notes was approximately $511.3 million. 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.

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 was scheduled to mature in August 2015 and replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility was 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 Additional First Lien Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. On December 20, 2012, the ABL credit facility was amended and restated as further discussed below.

In connection with the change in control described in Note 1 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 the IEP Acquisition 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 December 20, 2012, CRLLC, the Refining Partnership, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into an amended and restated ABL credit agreement (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility, which replaced the ABL credit facility described above, is scheduled to mature on December 20, 2017. Under the amended and restated facility, the Refining Partnership assumed the Company's position as borrower and the Company's obligations under the facility upon the closing of the Refining Partnership's IPO on January 23, 2013.

The Amended and Restated ABL Credit Facility is a senior secured asset based revolving credit facility in an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties and their subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit.

Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.

The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Credit Parties were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of March 31, 2013.

Lender and other third-party costs associated with the Amended and Restated ABL Credit Facility of $2.1 million were deferred and are being amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, a portion of the unamortized deferred financing costs associated with the ABL credit facility of approximately $2.8 million will continue to be amortized over the term of the Amended and Restated ABL Credit Facility.

As of March 31, 2013, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.8 million and had letters of credit outstanding of approximately $27.2 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of March 31, 2013.

On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a 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 March 31, 2013. There is no scheduled amortization of the credit facility, which matures in April 2016. The carrying value of the Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership.

The credit facility requires the Nitrogen Fertilizer 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, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, or enter into sale-leaseback transactions and affiliate transactions. The credit facility provides that the Nitrogen Fertilizer 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 March 31, 2013, CRNF was in compliance with the covenants contained in the credit facility.

As a result of the acquisition of the Wynnewood refinery, the Company acquired certain lease assets and assumed related capital lease obligations related to Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The underlying assets and related depreciation were included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 199 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 198 months remaining and will expire in September 2029.

On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Subject to declaration by its board of directors, CVR Energy's initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which the Company plans to begin paying in the second quarter of 2013. In addition, the Board of Directors of CVR Energy declared a special dividend of $5.50 per share, which was paid on February 19, 2013, to stockholders of record at the close of business on February 5, 2013. The total amount of the special dividend payment was approximately $477.6 million and is reflected as a reduction of retained earnings in the Condensed Consolidated Statement of Changes in Equity. Of this amount, approximately $391.6 million was paid to IEP in respect of its 82% ownership interest in the Company's shares.

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

Outstanding stock options of 22,900 were excluded from the diluted earnings (loss) per share calculation for the three months ended March 31, 2012, as they were antidilutive. For the three months ended March 31, 2012, 1,659,483 shares of non-vested common stock were excluded from the diluted loss per share calculation, as they were antidilutive to the net loss incurred. There were no equity awards outstanding during the three months ended March 31, 2013 as all unvested awards under the LTIP were liability awards. See Note 3 ("Share-Based Compensation").

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 which expire at various dates. For the three months ended March 31, 2013 and 2012, lease expense totaled approximately $2.3 million and $1.3 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.

On August 31, 2012, CRRM, and Vitol Inc. ("Vitol"), entered into an Amended and Restated Crude Oil Supply Agreement (the "Vitol Agreement"). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the "Previous Supply Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Refining Partnership's inventory position and mitigate crude oil pricing risk.

The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

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 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.

In May 2010, separate groups of plaintiffs (the "Anstine and Arrow cases") filed two lawsuits against CRRM and other defendants in state court in Oklahoma and Kansas. Both lawsuits were removed to federal court and were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware. The Anstine and Arrow cases allege the 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. Both lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. In February 2013, CRRM agreed to a settlement in the Anstine and Arrow cases. The settlement did not have a material adverse effect on the condensed consolidated financial statements.

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 IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of March 31, 2013.

On August 10, 2012, Deutsche Bank ("DB") filed suit against CVR in state court in New York, alleging that CVR failed to pay DB approximately $18.5 million in fees allegedly due to DB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB 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 IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of March 31, 2013.

On December 17, 2012, Gary Community Investment Company, F/K/A The Gary-Williams Company and GWEC Holding Company, Inc. (referred to herein collectively as "Gary-Williams") filed a lawsuit in the Supreme Court of New York, New York County (Gary Community Investment Co. v. CVR Energy, Inc., No. 654401/12) against CVR and CRLLC (referred to collectively for purposes of this paragraph as "CVR"). The action arises out of claims relating to CVR's purchase of the Wynnewood, Oklahoma refinery pursuant to the Purchase and Sale Agreement entered into by the parties on November 2, 2011 (the "Purchase Agreement"). Specifically, CVR provided notice to Gary-Williams that it sought indemnification for various breaches of the Purchase Agreement and subsequently made a claim notice for payment of the entire escrow property pursuant to the Escrow Agreement by an among Gary-Williams, CRLLC, and the escrow agent, dated as of December 15, 2011. Gary-Williams, in its lawsuit, alleges that CVR breached the Purchase Agreement and the Escrow Agreement, and is seeking a declaratory judgment that CVR's claims are without any legal basis, damages in an unspecified amount, and release of the full amount of the escrow property to Gary-Williams.

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 reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and 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 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended December 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2011, 2010, 2009 and 2008 and estimated and accrued for property tax for the year ended December 31, 2012. The first payment in respect to CRNF's 2012 property taxes was made in December 2012 and the second payment will be made in May 2013.

On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012, which will lower CRNF's property taxes by about $10.5 million per year for tax years 2013 through 2016 based on current mill levy rates. In addition, the settlement provides that Montgomery County will support CRNF's application before COTA for a ten year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment.

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.

On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the U.S. Environmental Protection Agency (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 recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the OPA. CRRM has reached an agreement with the DOJ resolving its claims under CWA and OPA. The agreement is memorialized in a Consent Decree that was filed and approved with the Court on February 12, 2013 and March 25, 2013, respectively, (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty plus accrued interest in the amount of $0.6 million for CWA violations and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training. The parties also are negotiating an agreement to settle DOJ's RMP claims. Any liability to DOJ related to the RMP claims is not expected to be material.

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 $25.0 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.

The petroleum and nitrogen fertilizer businesses 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, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Wynnewood Refining Company, LLC ("WRC") and Coffeyville Resources Terminal, LLC ("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 OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up 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 March 31, 2013 and December 31, 2012, environmental accruals of approximately $2.2 million and $2.3 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 $0.6 million and $0.7 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 March 31, 2013 and December 31, 2012, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million for two landfills at March 31, 2013 and December 31, 2012. 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 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. However, the change in control resulting from the IEP Acquisition in 2012 triggered the loss of small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Capital expenditures to comply with the rule are expected to be approximately $59.0 million for CRRM and $94.0 million for WRC.

The petroleum business 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, known as renewable identification numbers ("RINs"), 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 2013, about 9.6% of all transportation fuel is required to be "renewable fuel". Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending, and in 2013, the Wynnewood refinery was required to comply. From time to time, the petroleum business may purchase RINs on the open market or waiver credits for cellulosic biofuels from the EPA in order to comply with RFS. While the petroleum business cannot predict the future prices of RINs or waiver credits, the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year. If the petroleum business is unable to pass the costs of compliance with RFS on to its customers, if sufficient RINs are unavailable for purchase at times when the petroleum business seeks to purchase RINs, if the petroleum business has to pay a significant higher price for RINs or if the petroleum business is subject to penalties as a result of delays in its ability to timely deliver RINs to the EPA, its business, financial condition and results of operations could be materially adversely affected.

In 2013, the EPA proposed "Tier 3" gasoline sulfur standards. Based on the proposed standards, CRRM anticipates it will incur less than $20.0 million of capital expenditures to install controls in order to meet the anticipated new standards. The project is expected to be completed during the Coffeyville refinery's next scheduled turnaround in 2016. It is not anticipated that the Wynnewood refinery will require additional controls or capital expenditures to meet the anticipated new standard.

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 clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.

In March 2012, CRRM entered into a "Second Consent Decree" with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). 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 non-compliance 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. Under the Second Consent Decree,

the Company was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $41.0 million, of which approximately $39.0 million is expected to consist of capital expenditures for air pollution control equipment. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. Additional incremental capital expenditures associated with the Second Consent Decree will 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 U.S. District Court for the District of Kansas 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. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be $2.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.

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 Oklahoma Pollutant Discharge Elimination System 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, the Company does not anticipate that the costs of any required additional controls or operational changes would be material.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended March 31, 2013 and 2012, capital expenditures were approximately $22.2 million and $5.3 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

CRRM, CRNF, CRCT, WRC and CRT each believe 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.

On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during startup after a short outage as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there was no environmental impact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. The petroleum business completed an internal investigation of the incident and continues to cooperate with OSHA and Oklahoma Department of Labor ("ODL") investigations. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program ("SVEP"). WRC has filed its notice of contest against the citations, and will vigorously defend against the citations and OSHA's placement of WRC in the SVEP. WRC is in the process of reviewing the citations and no settlement has been reached. Any penalties associated with OSHA's citations are not expected to have a material adverse effect on the condensed consolidated financial statements.

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, liabilities or a group of assets or liabilities, such as a business.

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 March 31, 2013 and December 31, 2012:

	March 31, 2013

	Level 1		Level 2			Level 3		Total
	(in thousands)
Location and Description
Cash equivalents	$	133,929	$	—		$	—	$	133,929
Other current assets (marketable securities)		50		—			—		50
Other current assets (other derivative agreements)		—		—			—		—
Other long-term assets (other derivative agreements)		—		1,461			—		1,461

Total Assets	$	133,979	$	1,461		$	—	$	135,440

Other current liabilities (other derivative agreements)		—		(35,781	)		—		(35,781	)
Other current liabilities (interest rate swap)		—		(840	)		—		(840	)
Other current liabilities (other fair value measurements)		—		(31,960	)		—		(31,960	)
Other long-term liabilities (other derivative agreements)		—		—			—		—
Other long-term liabilities (interest rate swap)		—		(1,699	)		—		(1,699	)

Total Liabilities	$	—	$	(70,280	)	$	—	$	(70,280	)

	December 31, 2012

	Level 1		Level 2			Level 3		Total
	(in thousands)
Location and Description
Cash equivalents	$	133,897	$	—		$	—	$	133,897
Other current assets (marketable securities)		38		—			—		38
Other current assets (other derivative agreements)		—		—			—		—
Other long-term assets (other derivative agreements)		—		938			—		938

Total Assets	$	133,935	$	938		$	—	$	134,873

Other current liabilities (other derivative agreements)		—		(67,747	)		—		(67,747	)
Other current liabilities (interest rate swap)		—		(861	)		—		(861	)
Other current liabilities (other fair value measurements)		—		(1,072	)		—		(1,072	)
Other long-term liabilities (other derivative agreements)		—		—			—		—
Other long-term liabilities (interest rate swap)		—		(1,890	)		—		(1,890	)

Total Liabilities	$	—	$	(71,570	)	$	—	$	(71,570	)

As of March 31, 2013 and December 31, 2012, 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, derivative instruments and certain other current liabilities. Additionally, the fair value of the Company's debt issuances is disclosed in Note 8 ("Long-Term Debt"). The Refining Partnership's commodity derivative contracts and other current liabilities which use fair value measurements are valued using broker quoted market prices of similar instruments which are considered Level 2 inputs. The Nitrogen Fertilizer 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, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. 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. The Company had no transfers of assets or liabilities between any of the above levels during the three months ended March 31, 2013.

The Refining Partnership and Nitrogen Fertilizer Partnership are 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 Refining Partnership from time to time enters into various commodity derivative transactions.

The Refining Partnership has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. The Refining Partnership 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 loss on derivatives, net in the Condensed Consolidated Statements of Operations.

The Refining Partnership 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. Dependent 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, the Refining Partnership may be required to deposit additional funds into this margin account. The fair value of the open commodity positions as of March 31, 2013 was a net loss of $0.3 million included in other current liabilities. For the three months ended March 31, 2013 and 2012, the Refining Partnership recognized a realized loss of $2.0 million and $8.2 million, respectively, which is recorded in realized loss on derivatives, net in the Condensed Consolidated Statements of Operations. For the three months ended March 31, 2013 and 2012, the Refining Partnership recognized an unrealized loss of $0.2 million and unrealized gain of $0.2 million, respectively, which are recorded in unrealized gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. 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 March 31, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 22.8 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at March 31, 2013 was a net unrealized loss of $34.1 million, $35.5 million of which is included in current liabilities and $1.4 million is included in non-current assets. For the three months ended March 31, 2013 and 2012, the Refining Partnership recognized a realized loss of $50.5 million and $10.9 million, respectively, which is recorded in realized loss on derivatives, net in the Condensed Consolidated Statements of Operations. For the three months ended March 31, 2013 and 2012, the Refining Partnership recognized an unrealized gain of $32.7 million and unrealized loss of $128.3 million, respectively, which are recorded in unrealized gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements are 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 calculated under the CRNF credit agreement. At March 31, 2013, the effective rate was approximately 4.58%. 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 Statements of Operations. The realized loss on the interest rate swap re-classed from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.3 million and $0.2 million for three months ended March 31, 2013 and 2012, respectively. For the three months ended March 31, 2013 and 2012, the decrease in the fair value of the interest rate swap agreements of $46,000 and $0.2 million, respectively, which was unrealized, was recognized in accumulated other comprehensive income.

The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by the Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. The interest rate swap agreements held by the Nitrogen Fertilizer Partnership also provide for the right to setoff. However, as the interest rate swaps are in a liability position, there are no amounts offset in the Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets and Liabilities," the tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Condensed Consolidated Balance Sheets for the various types of open derivative positions at the Refining Partnership.

The offsetting assets and liabilities for the Refining Partnership's derivatives as of March 31, 2013 are recorded as non-current assets in other long-term assets in the Condensed Consolidated Balance

Sheets and as current liabilities in other current liabilities in the Condensed Consolidated Balance Sheets as follows:

The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2012 are recorded as non-current assets in other long-term assets in the Condensed Consolidated Balance Sheets and as current liabilities in other current liabilities in the Condensed Consolidated Balance Sheets as follows:

In May 2012, IEP announced that it 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 March 31, 2013, IEP owned approximately 82% of all common shares outstanding.

Since March 2009, the Company, through the Nitrogen Fertilizer Partnership, has leased 199 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 months ended March 31, 2013, $0.3 million 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 March 31, 2013, the Company has recorded approximately $57.2 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended March 31, 2013 the Company made no payments to AEPC under the Tax Allocation Agreement. In April 2013, the Company paid $54.0 million for the first quarter estimated federal income tax payment due to AEPC under the Tax Allocation Agreement.

Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed and controlled by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013 CVR Energy acquired a minority equity interest in Insight Portfolio Group and agreed to pay a portion of Insight Portfolio Group's operating expenses in 2013. The Company paid Insight Portfolio Group approximately $0.1 million during the three months ended March 31, 2013. The Company may purchase a variety of goods and services as members of the buying group at prices and terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.

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, propane, and petroleum refining by-products, including pet coke. The Petroleum Segment's Coffeyville refinery sells pet coke to the Nitrogen Fertilizer 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 $2.7 million and $2.4 million for the three months ended March 31, 2013 and 2012, respectively.

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases described below under "Nitrogen Fertilizer" of approximately $29,000 and $5.7 million for the three months ended March 31, 2013 and 2012, respectively. For the three months ended March 31, 2013 and 2012, the net sales recorded as intercompany sales from the sale of hydrogen to the Nitrogen Fertilizer Partnership were approximately $0.2 million and $0, 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 $2.6 million and $3.0 million for the three months ended March 31, 2013 and 2012 respectively.

Pursuant to the feedstock agreement, the Company's segments have the right to transfer excess hydrogen between the Coffeyville refinery and nitrogen fertilizer plant. 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 March 31, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $29,000 and $5.7 million, respectively. For the three months ended March 31, 2013 and 2012, the nitrogen fertilizer segment also recognized approximately $0.2 million and $0, 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, corporate cash and cash equivalents, 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 March 31,

	2013			2012
	(in thousands)
Net sales
Petroleum	$	2,274,018		$	1,898,485
Nitrogen Fertilizer		81,411			78,276
Intersegment elimination		(3,010	)		(8,130	)

Total	$	2,352,419		$	1,968,631

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,805,774		$	1,630,665
Nitrogen Fertilizer		10,655			12,598
Intersegment elimination		(2,847	)		(8,108	)

Total	$	1,813,582		$	1,635,155

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	86,046		$	92,703
Nitrogen Fertilizer		22,557			22,837
Other		(55	)		(26	)

Total	$	108,548		$	115,514

	Three Months Ended March 31,

	2013			2012
	(in thousands)
Depreciation and amortization
Petroleum	$	27,951		$	26,259
Nitrogen Fertilizer		5,767			5,438
Other		480			415

Total	$	34,198		$	32,112

Operating income (loss)
Petroleum	$	335,600		$	134,896
Nitrogen Fertilizer		36,803			31,426
Other		(4,741	)		(25,814	)

Total	$	367,662		$	140,508

Capital expenditures
Petroleum	$	44,582		$	35,403
Nitrogen fertilizer		18,063			22,274
Other		1,074			1,848

Total	$	63,719		$	59,525

On April 30, 2013, the board of directors of the Company declared a cash dividend for the first quarter of 2013 to the Company's stockholders of $0.75 per share or $65.1 million in aggregate. The dividend will be paid on May 17, 2013 to stockholders of record at the close of business on May 10, 2013. IEP will receive $53.4 million in respect of its 82% ownership interest in the Company's shares.

On April 26, 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the first quarter of 2013 to the Nitrogen Fertilizer Partnership's unitholders of $0.610 per common unit or $44.6 million in aggregate. The cash distribution will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013. The Company will receive $31.1 million in respect of its Nitrogen Fertilizer Partnership common units.

On April 30, 2013, the board of directors of the Refining Partnership's general partner declared a cash distribution for the first quarter of 2013 to the Refining Partnership's unitholders of $1.58 per common unit or $233.2 million in aggregate. The cash distribution will be paid on May 17, 2013 to unitholders of record at the close of business on May 10, 2013. The Company will receive $189.6 million in respect of its Refining Partnership common units. This distribution was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).

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 unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission ("SEC") on March 14, 2013. Results of operations for the three months ended March 31, 2013 are not necessarily indicative of results to be attained for any other period.

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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, 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 in the summary risks noted below:

All forward-looking statements contained in this Report 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 Report, or to reflect the occurrence of unanticipated events.

We are a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through our holdings in the Refining Partnership and the Nitrogen Fertilizer Partnership. The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of ammonia and UAN. We own the general partner and a majority of the common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership.

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. The petroleum business consists of our interest in the Refining Partnership. We own the general partner and approximately 81% of the common units of the Refining Partnership. The petroleum business consists of a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpd medium complexity crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). In addition, its supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum 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's refined petroleum 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 the Coffeyville refinery 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) 1.0 million barrels of company owned crude oil storage capacity in Cushing, Oklahoma, (6) an additional 3.3 million barrels of leased crude oil storage capacity located in Cushing and (7) approximately 4.5 million barrels of combined refinery related storage capacity.

The 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 the Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. The early June 2012 reversal of the Seaway pipeline that now flows from Cushing, Oklahoma to the U.S. Gulf Coast has eliminated the ability to source foreign waterborne crude oil, as well as deep water 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), Coffeyville makes bulk sales (sales through third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise, and NuStar.

Crude oil is supplied to the Coffeyville refinery through the gathering system and by a pipeline owned by Plains that runs from Cushing to its Broome Station tank farm. The petroleum business maintains capacity on the Spearhead and Keystone pipelines from Canada to Cushing. It also maintains leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. The Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades and various Canadian medium and heavy sours and sweet synthetics. Crude oil is supplied to the Wynnewood refinery through two third-party pipelines operated by Sunoco Pipeline and Excel Pipeline and historically has mainly been sourced from Texas and Oklahoma. The 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 petroleum business expects to spend approximately $50.0 million on a hydrocracker project that will increase the conversion capability and the ULDS yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of the refineries allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the first quarter of 2013 was $4.98 per barrel compared to $1.70 per barrel in the first quarter of 2012.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. We own the general partner and approximately 70% of the common units of the Nitrogen Fertilizer 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 3,000 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. For the three months ended March 31, 2013, the nitrogen fertilizer business produced 111,352 tons of ammonia, of which approximately 72% was upgraded into 196,157 tons of UAN.

The Nitrogen Fertilizer Partnership will continue to expand the nitrogen fertilizer business' existing asset base to execute its growth strategy. The Nitrogen Fertilizer Partnership's growth strategy includes expanding production of UAN and acquiring additional infrastructure and production assets. The Nitrogen Fertilizer Partnership completed a significant two-year plant expansion designed to increase its UAN production capacity by 400,000 tons, or approximately 50%, per year. The UAN expansion was completed in February 2013 and was at full rates prior to the end of the first quarter. The Nitrogen Fertilizer Partnership now upgrades substantially all of the ammonia it produces into higher margin UAN fertilizer.

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 businesses' competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been 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 the Refining Partnership pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During 2012, the Nitrogen Fertilizer Partnership entered into a pet coke supply agreement with HollyFrontier Corporation. The initial term ends in December 2013 and is 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 the Refining Partnership's crude oil refinery in Coffeyville.

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with IEP Energy, LLC and certain of its affiliates (collectively "IEP"). Pursuant to the Transaction Agreement, IEP offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock for a price of $30.00 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.

In May 2012, IEP acquired a majority of the common stock of CVR Energy through the Offer. As a result of shares tendered into the Offer during the initial offering period and subsequent additional purchases, IEP owned approximately 82% of CVR Energy's outstanding common stock as of March 31, 2013.

On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at a price of $25.00 per common unit, resulting in gross proceeds of $600.0 million. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per common unit resulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."

Prior to the Refining Partnership IPO, CVR owned 100% of the Refining Partnership and net income earned during this period was fully attributable to the Company. Following the Refining Partnership IPO, CVR Energy indirectly owns approximately 81% of the Refining Partnership's

outstanding common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partner interest.

The earnings and cash flows of the petroleum business are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond its 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 the petroleum business applies first-in, first-out ("FIFO") accounting to value its inventory, crude oil price movements may impact net income in the short term because of changes in the value of its 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.

The prices of crude oil and other feedstocks 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. Widespread expansion or upgrades of competitors' facilities, price volatility, international political and economic developments and other factors 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. The petroleum business is also subject to the EPA's Renewable Fuel Standard ("RFS"), which requires it to blend "renewable fuels" in with its transportation fuels or purchase renewable energy credits, known as renewable identification numbers, in lieu of blending. In 2013, the Wynnewood refinery became subject to the RFS for the first time, and the cost of RINs became extremely volatile and significantly higher than the cost during the comparable 2012 period. See Note 11 to our condensed consolidated financial statements for further information

In order to assess the operating performance of the petroleum business, we compare net sales, less cost of product sold (exclusive of depreciation and amortization), or the 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 the refinery margin, because the refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and their product yield is less than total refinery throughput, the crack spread does not account for all the factors

that affect refinery margin. The 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. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutene, gasoline components, and normal butane are also typically used. We measure the cost advantage of the crude oil slate by calculating the spread between the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. The refinery margin can be impacted significantly by the consumed crude oil differential. The 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 the consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil the petroleum business purchases 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.

The petroleum business produces a high volume of high value products, such as gasoline and distillates. The petroleum business benefits from the fact that its marketing region consumes more refined products than it produces resulting in prices that reflect the logistics cost for U.S. Gulf Coast refineries to ship into its 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 its refineries is that prices the petroleum business realizes are different than those used in determining the 2-1-1 crack spread. The difference between its 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 its marketing area exceed those used in the 2-1-1 crack spread.

The direct operating expense structure is also important to the petroleum business' profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. The predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. The petroleum business is therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the three months ended March 31, 2013, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $2.4 million.

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

Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results of operations. Unplanned downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The 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. The Coffeyville refinery completed the first phase of a two phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. The Wynnewood Refinery completed a turnaround in December 2012. Its next turnaround is scheduled to begin in late 2016.

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, the 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 last ten years, natural gas prices have significantly decreased. This decrease has significantly lowered our competitors' cost of producing nitrogen fertilizer.

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 2012, approximately 54% of the corn planted in the United States was grown within a $45 per 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 are derived from the lower margin industrial market. 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 significant intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $15 per UAN ton for transportation of UAN 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 months ended March 31, 2013, the nitrogen fertilizer business upgraded approximately 72% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. As a result of the completion of the UAN expansion project, the nitrogen fertilizer business expects that it will now upgrade substantially all of its ammonia into UAN. UAN production is a major contributor to the nitrogen fertilizer business' 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 months ended March 31, 2013 and 2012, the nitrogen fertilizer business spent approximately $4.0 million and $5.0 million, respectively, for pet coke, which equaled an average cost per ton of $31 and $42, respectively.

The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from the adjacent Coffeyville crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder through a third-party contact with HollyFrontier Corporation. 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.

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 $3.0 million to $5.0 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2012, at a cost of approximately $4.8 million. The next turnaround is currently scheduled for the fourth quarter of 2014.

In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Nitrogen Fertilizer Partnership in October 2007, we entered into a number of agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the nitrogen fertilizer business on the one hand and the refining business on the other hand. In connection with the Nitrogen Fertilizer Partnership IPO, certain of the intercompany agreements were amended and restated, and the nitrogen fertilizer business and the refining business entered into several new agreements. In connection with the Refining Partnership IPO, some of our subsidiaries party to these agreements became subsidiaries of the Refining Partnership.

These intercompany agreements include (i) the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operates the nitrogen fertilizer business; (iii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iv) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v) an easement agreement; (vi) an environmental agreement; and (vii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to the Nitrogen Fertilizer 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.

In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $150.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business.

On August 31, 2012, CRRM and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the "Previous Supply Agreement"). Under the agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

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, IEP 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, IEP announced that control of the Company had been acquired. CVR incurred related costs of approximately $14.8 million for the three months ended March 31, 2012 that did not occur in 2013. 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.

Notes. In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, 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 "Old Notes").

In December 2010, CRLLC made a voluntary unscheduled payment of $27.5 million on the First Lien Notes. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million of the First Lien Notes to partially fund the acquisition of the Wynnewood refinery. In connection with the acquisition of the Wynnewood refinery, 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.

On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. A portion of the remaining net proceeds from the 2022 Notes offering were used to fund the redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the three months ended March 31, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

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 in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. 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-classified award to a liability-classified award due to the cash settlement of the awards. For the three months ended March 31, 2013 and 2012, we incurred compensation expense of $5.4 million and $3.3 million, respectively, related to non-vested share-based compensation awards related to the LTIP.

Through the CVR Partners, LP Long-Term Incentive Plan ("CVR Partners LTIP"), shares of non-vested common units and phantom units may be awarded to (1) employees of the Nitrogen Fertilizer Partnership, (2) employees of the general partner and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. The

amendment triggered a modification to the awards by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. For each of the three months ended March 31, 2013 and 2012, we incurred compensation expense of $0.6 million, related to non-vested share-based compensation awards related to the CVR Partners LTIP.

Prior to the Refining Partnership IPO on January 23, 2013, the noncontrolling interest reflected in our condensed consolidated financial statements represented the approximately 30% interest in the Nitrogen Fertilizer Partnership held by common unitholders, which was adjusted each reporting period for the noncontrolling ownership percentage of the Nitrogen Fertilizer Partnership's net income and related distributions. As a result of the Refining Partnership IPO, CVR Energy recorded an additional noncontrolling interest for the Refining Partnership common units sold into the public market, which represented an approximately 19% interest of the Refining Partnership. Effective with the Refining Partnership's IPO, the noncontrolling interest reflected on the Condensed Consolidated Balance Sheets will be impacted additionally, by the noncontrolling ownership percentage of the net income of the Refining Partnership and related distributions for each future reporting period. The revenue and expenses from the Refining Partnership and Nitrogen Fertilizer Partnership are consolidated with CVR Energy's Condensed Consolidated Statements of Operations because each of the general partners is owned by CVR Refining Holdings, LLC and CRLLC, respectively, wholly-owned subsidiaries of CVR Energy. Therefore, CVR Energy has the ability to control the activities of the Refining Partnership and Nitrogen Fertilizer Partnership. However, the percentage of ownership held by the public unitholders for the Refining Partnership and the Nitrogen Fertilizer Partnership is reflected as net income attributable to noncontrolling interest in our Condensed Consolidated Statements of Operations and reduces consolidated net income to derive net income attributable to CVR Energy.

Our general and administrative expenses will increase in 2013 in part due to the costs of the Refining Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, will approximate $5.0 million per year, excluding the costs associated with the initial implementation of the Refining Partnership's Sarbanes-Oxley Section 404 internal controls review and testing. These increased costs will be paid by the Refining Partnership. Our historical condensed consolidated financial statements for periods ended prior to January 23, 2013 do not reflect the impact of these expenses, which affects the comparability of the post-Refining Partnership IPO results with our financial statements from periods prior to the completion of the Refining Partnership IPO.

$11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended December 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2011, 2010, 2009 and 2008 and estimated and accrued for property tax for the year ended December 31, 2012. The first payment in respect to CRNF's 2012 property taxes was made in December 2012 and the second payment will be made in May 2013.

The current policy of the board of directors of the Nitrogen Fertilizer Partnership's general partner is to distribute all of the available cash the Nitrogen Fertilizer Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partner following the end of such quarter. Beginning with the first quarter of 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner has adopted an amended policy to calculate available cash starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for net interest expense (excluding capitalized interest) and debt service and other contractual obligations, maintenance capital expenditures and, to the extent applicable, major scheduled turnaround expense incurred and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership's general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership's general partner. Actual distributions are set by the board of directors of the Nitrogen Fertilizer Partnership's general partner. The board of directors of the Nitrogen Fertilizer Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to make distributions at all.

On February 14, 2013, the Nitrogen Fertilizer Partnership paid out a cash distribution to the Nitrogen Fertilizer Partnership's unitholders of record at the close of business on February 7, 2013 for the fourth quarter of 2012 in the amount of $0.192 per unit, or $14.0 million in aggregate. We received $9.8 million in respect of our common units.

On April 26, 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the first quarter of 2013 to the Nitrogen Fertilizer Partnership's unitholders of $0.610 per common unit or $44.6 million in aggregate. The cash distribution will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013. We will receive $31.1 million in respect of our common units.

The current policy of the board of directors of the Refining Partnership's general partner is to distribute all of the available cash the Refining Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future

operating or capital needs that the board of directors of the Refining Partnership's general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, at the discretion of the board of directors of the Refining Partnership's general partner. Actual distributions are set by the board of directors of the Refining Partnership's general partner. The board of directors of the Refining Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions at all.

On April 30, 2013, the board of directors of the Refining Partnership's general partner declared a cash distribution for the first quarter of 2013 to the Refining Partnership's unitholders of $1.58 per common unit or $233.2 million in aggregate. The cash distribution will be paid on May 17, 2013 to unitholders of record at the close of business on May 10, 2013. We will receive $189.6 million in respect of our common units. This distribution was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).

On April 30, 2013, the board of directors of the Company declared a dividend of $0.75 per share or $65.1 million in aggregate. The dividend will be paid on May 17, 2013 to stockholders of record at the close of business on May 10, 2013.

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three months ended March 31, 2013 and 2012. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Report. 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, 2012, is unaudited.

	Three Months Ended March 31,						Change from 2012

	2013			2012			Change			Percent
	(in millions, except per share amount)
Consolidated Statement of Operations Data:
Net sales	$	2,352.4		$	1,968.6		$	383.8			19.5	%
Cost of product sold(1)		1,813.6			1,635.2			178.4			10.9
Direct operating expenses(1)		108.5			115.5			(7.0	)		(6.1	)
Selling, general and administrative expenses(1)		28.4			45.3			(16.9	)		(37.3	)
Depreciation and amortization(1)		34.2			32.1			2.1			6.5

Operating income		367.7			140.5			227.2			161.7
Interest expense and other financing costs		(15.4	)		(19.2	)		3.8			(19.8	)
Gain (loss) on derivatives, net
Realized		(52.5	)		(19.1	)		(33.4	)		174.9
Unrealized		32.5			(128.1	)		160.6			(125.4	)
Loss on extinguishment of debt		(26.1	)		—			(26.1	)		—
Other income, net		0.3			0.1			0.2			200.0

Income (loss) before income tax expense (benefit)		306.5			(25.8	)		332.3			1,288.0
Income tax expense (benefit)		93.8			(9.8	)		103.6			1,057.1

Net income (loss)(2)		212.7			(16.0	)		228.7			1,429.4
Less: Net income attributable to noncontrolling interest		47.7			9.2			38.5			418.5

Net income (loss) attributable to CVR Energy stockholders	$	165.0		$	(25.2	)	$	190.2			754.8	%

Basic earnings per share	$	1.90		$	(0.29	)	$	2.19			755.2	%
Diluted earnings per share	$	1.90		$	(0.29	)	$	2.19			755.2	%
Weighted-average common shares outstanding:
Basic		86,831,050			86,808,150			22,900			—
Diluted		86,831,050			86,808,150			22,900			—

repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million in the first quarter of 2013, which includes the premium paid of $20.6 million, the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

(b): Consists of fees which are expensed to selling, general and administrative expenses in connection with letters of credit outstanding.
(c): Represents expenses associated with major scheduled turnarounds in the petroleum segment.
(d): Represents the impact of share-based compensation awards.
(e): On December 15, 2011, CRLLC acquired the stock of WEC (formerly known as Gary-Williams Energy Corporation) and its wholly-owned subsidiaries which owned a 70,000 barrel per day refinery in Wynnewood, Oklahoma. Included in Acquisition and integration expenses—Gary-Williams are legal and other professional fees associated with the acquisition and certain costs incurred in 2012 associated with the preliminary integration of the acquired business.

Net Sales. Consolidated net sales were $2,352.4 million for the three months ended March 31, 2013 compared to $1,968.6 million for the three months ended March 31, 2012. The increase of $383.8 million was primarily due to higher overall sales volume at the petroleum segment, which was partially offset by lower product prices. The petroleum segment's average sales price per gallon for the three months ended March 31, 2013 of $2.82 for gasoline and $3.11 for distillates decreased by 1.7% and 0.3% respectively, as compared to for the three months ended March 31, 2012. The nitrogen fertilizer segment net sales increased by $3.1 million primarily due to higher UAN sales volumes as a result of the completion of the UAN expansion and higher ammonia sales prices, partially offset by lower UAN sales prices and lower ammonia sales volumes.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $1,813.6 million for the three months ended March 31, 2013, as compared to $1,635.2 million for the three months ended March 31, 2012. The increase of $178.4 million primarily resulted from an increase in crude oil throughputs in the petroleum segment, which was partially offset by a decrease in crude oil prices. The increase in the petroleum segment was partially offset by lower cost of product sold (exclusive of depreciation and amortization) in the nitrogen fertilizer segment, which was primarily driven by a decrease in cost of consumed pet coke from the prior year period.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $108.5 million for the three months ended March 31, 2013, as compared to $115.5 million for the three months ended March 31, 2012. The decrease of $7.0 million was due primarily to decreases in major scheduled turnaround expenses in the petroleum segment, partially offset by increased expenses for repairs and maintenance, energy and utility costs, and outside services. The nitrogen fertilizer segment also had a decrease in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of lower property taxes, partially offset by higher costs for utilities, labor and insurance.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $28.4 million for the three months ended March 31, 2013, as compared to $45.3 million for the three months ended March 31, 2012. The $16.9 million decrease was primarily the result of a decrease in proxy expenses of $14.8 million related to the tender offer by certain entities affiliated with IEP and a decrease in integration costs of $3.7 million related to the acquisition of the Wynnewood refinery, which were partially offset by an increase in share-based compensation costs of $1.6 million.

Operating Income. Consolidated operating income was $367.7 million for the three months ended March 31, 2013, as compared to operating income of $140.5 million for the three months ended March 31, 2012, an increase of $227.2 million. Petroleum segment operating income increased $200.7 million primarily as a result of higher refining margins and lower direct operating expenses. Nitrogen fertilizer segment operating income increased $5.4 million primarily as a result of higher nitrogen fertilizer margins and lower cost of product sold. Decreased selling, general and administrative expenses discussed above also had a favorable impact on operating income for the period.

Interest Expense. Consolidated interest expense for the three months ended March 31, 2013 was $15.4 million as compared to $19.2 million for the three months ended March 31, 2012. This $3.8 million decrease resulted primarily from lower interest expense on the outstanding 2022 Notes for the three months ended March 31, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the three months ended March 31, 2012.

Gain (loss) on Derivatives, net. For the three months ended March 31, 2013, we recorded a $20.0 million net loss on derivatives. This compares to a $147.2 million net loss on derivatives for the three months ended March 31, 2012. The change in gain (loss) on derivatives was primarily due to changes in crack spreads during the periods. The petroleum segment entered into several over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2013.

Loss on Extinguishment of Debt. For the three months ended March 31, 2013, we incurred a $26.1 million loss on extinguishment of debt. The loss on extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid, the write-off of previously deferred financing costs and the write-off of the unamortized original issuance discount.

Income Tax Expense (Benefit). Income tax expense for the three months ended March 31, 2013 was $93.8 million or 30.6% of income before income taxes, as compared to an income tax benefit for the three months ended March 31, 2012 of $9.8 million or 37.8% of loss before income tax benefit. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with our noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings and the benefits related to the domestic production activities deduction.

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

	Three Months Ended March 31,

	2013		2012
	(unaudited) (in millions)
Consolidated Petroleum Segment Summary Financial Results
Net sales	$	2,274.0	$	1,898.5
Cost of product sold(1)		1,805.8		1,630.7
Direct operating expenses(1)		86.0		71.7
Major scheduled turnaround expenses		—		21.0
Depreciation and amortization		28.0		26.3

Gross profit(3)		354.2		148.8
Plus direct operating expenses and major scheduled turnaround expenses(1)		86.0		92.7
Plus depreciation and amortization		28.0		26.3

Refining margin(4)		468.2		267.8
Operating income	$	335.6	$	134.9
Adjusted Petroleum EBITDA(5)	$	309.9	$	144.9

	Three Months Ended March 31,

	2013				2012
			%				%
Refining Throughput and Production Data (barrels per day)
Throughput:
Sweet		156,725		76.6		110,636		71.2
Medium		14,757		7.2		24,982		16.1
Heavy sour		23,334		11.4		11,040		7.1

Total crude oil throughput		194,816		95.2		146,658		94.4
All other feedstocks and blendstocks		9,774		4.8		8,727		5.6

Total throughput		204,590		100.0		155,385		100.0

Production:
Gasoline		98,184		47.8		81,291		52.6
Distillate		83,841		40.8		62,329		40.4
Other (excluding internally produced fuel)		23,543		11.4		10,879		7.0

Total refining production (excluding internally produced fuel)		205,568		100.0		154,499		100.0

Product price (dollars per gallon):
Gasoline	$	2.82			$	2.87
Distillate	$	3.11			$	3.12

	Three Months Ended March 31,

	2013			2012
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	94.36		$	103.03
Crude Oil Differentials:
WTI less WTS (light/medium sour)		6.33			3.67
WTI less WCS (heavy sour)		27.26			27.12
NYMEX Crack Spreads:
Gasoline		31.24			25.44
Heating Oil		33.43			29.61
NYMEX 2-1-1 Crack Spread		32.33			27.53
PADD II Group 3 Basis:
Gasoline		(7.57	)		(6.78	)
Ultra Low Sulfur Diesel		2.09			(1.64	)
PADD II Group 3 Product Crack:
Gasoline		23.66			18.66
Ultra Low Sulfur Diesel		35.52			27.98
PADD II Group 3 2-1-1		29.59			23.32

(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 refineries' performance as a general indication of the amount above the cost of product sold that it is 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 the petroleum business' Statements of Operations. The petroleum business' calculation of refining margin may differ from similar calculations of other companies in its 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 for greater transparency in the review of our overall business, financial, operational and economic financial performance.
(5): Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) major scheduled turnaround expenses, (iv) realized gain (loss) on derivatives, net, (v) depreciation and amortization and (vi) other income (expense). We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted Petroleum EBITDA enables investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, evaluate the petroleum segment's ongoing operating results and allows for greater transparency in reviewing the petroleum segment's overall financial, operational and economic performance. Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,

	2013		2012
	(unaudited) (in millions)
Coffeyville Refinery Financial Results
Net sales	$	1,492.6	$	1,132.5
Cost of product sold (exclusive of depreciation and amortization)		1,195.1		973.1
Direct operating expenses (exclusive of depreciation and amortization)		52.2		43.8
Major scheduled turnaround expense		—		20.1
Depreciation and amortization		17.5		17.3

Gross profit	$	227.8	$	78.2
Plus direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)		52.2		63.9
Plus depreciation and amortization		17.5		17.3

Refining margin	$	297.5	$	159.4

	Three Months Ended March 31,

	2013				2012
			%				%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Sweet		99,793		76.0		71,916		76.7
Medium		512		0.4		5,447		5.8
Heavy sour		23,334		17.8		11,040		11.8

Total crude oil throughput		123,639		94.2		88,403		94.3
All other feedstocks and blendstocks		7,570		5.8		5,367		5.7

Total throughput		131,209		100.0		93,770		100.0

Production:
Gasoline		62,414		46.7		50,269		53.0
Distillate		55,602		41.6		41,075		43.3
Other (excluding internally produced fuel)		15,717		11.7		3,492		3.7

Total refining production (excluding internally produced fuel)		133,733		100.0		94,836		100.0

	Three Months Ended March 31,

	2013		2012
	(unaudited)
	(in millions)
Wynnewood Refinery Financial Results
Net sales	$	780.4	$	766.0
Cost of product sold (exclusive of depreciation and amortization)		610.4		658.0
Direct operating expenses (exclusive of depreciation and amortization)		33.8		27.9
Major scheduled turnaround expenses		—		0.9
Depreciation and amortization		9.3		8.3

Gross profit	$	126.9	$	70.9
Plus direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)		33.8		28.8
Plus depreciation and amortization		9.3		8.3

Refining margin	$	170.0	$	108.0

	Three Months Ended March 31,

	2013				2012
			%				%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Sweet		56,932		77.6		38,720		62.8
Medium		14,245		19.4		19,535		31.7
Heavy sour		—		—		—		—

Total crude oil throughput		71,177		97.0		58,255		94.5
Feedstocks and blendstocks		2,204		3.0		3,360		5.5

Total throughput		73,381		100.0		61,615		100.0

Production:
Gasoline		35,770		49.8		31,022		52.0
Distillate		28,239		39.3		21,254		35.6
Other (excluding internally produced fuel)		7,826		10.9		7,387		12.4

Total refining production (excluding internally produced fuel)		71,835		100.0		59,663		100.0

Net Sales. Petroleum net sales were $2,274.0 million for the three months ended March 31, 2013 compared to $1,898.5 million for the three months ended March 31, 2012. The increase of $375.5 million was the result of higher overall sales volume, which was partially offset by lower product prices. The higher sales volume is due to the downtime associated with completion of the second phase of the Coffeyville refinery's turnaround in the first quarter of 2012, which decreased products available for sale. Our average sales price per gallon for the three months ended March 31, 2013 for gasoline of $2.82 and distillate of $3.11 decreased by approximately 1.7% and 0.3%, respectively, as compared to the three months ended March 31, 2012.

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 $1,805.8 million for the three months ended March 31, 2013 compared to $1,630.7 million for the three months ended March 31, 2012. The increase of $175.1 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 downtime associated with completion of the second phase of the Coffeyville refinery's turnaround in the first quarter of 2012. Our average cost per barrel of crude oil consumed for the three months ended March 31, 2013 was $89.34 compared to $101.25 for the comparable period of 2012, a decrease of approximately 11.8%. Sales volume of refined fuels increased by approximately 21.0%. 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 March 31, 2013, we had a favorable FIFO inventory impact of $4.7 million compared to a favorable FIFO inventory impact of $19.3 million for the comparable period of 2012.

Refining margin per barrel of crude oil throughput increased from $20.07 for the three months ended March 31, 2012 to $26.71 for the three months ended March 31, 2013. Refining margin adjusted for FIFO impact was $26.44 per crude oil throughput barrel for the three months ended March 31, 2013, as compared to $18.62 per crude oil throughput barrel for the three months ended March 31, 2012. Gross profit per barrel increased to $20.20 for the three months ended March 31, 2013 as compared to gross profit per barrel of $11.15 in the equivalent period in 2012. The increase of our refining margin per barrel is due to a decrease in our cost of consumed crude oil which was partially offset by a decrease in the average sales prices of our produced gasoline and distillates. Consumed crude oil costs decreased due to an 8.4% decrease in WTI for the three months ended March 31, 2013 over the three months ended March 31, 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 $86.0 million for the three months ended March 31, 2013 compared to direct operating expenses and major scheduled turnaround expenses of $92.7 million for the three months ended March 31, 2012. The decrease of $6.7 million was primarily the result of the decrease in expenses associated with major scheduled turnaround in the prior year ($21.0 million) and were partially offset by increases of expenses associated with general repairs and maintenance ($7.9 million), energy and utility costs ($4.0 million) and outside services ($2.9 million). Our Coffeyville refinery completed the second phase of its planned turnaround in March 2012. Direct operating expenses per barrel of crude oil throughput for the three months ended March 31, 2013 decreased to $4.91 per barrel as compared to $6.95 per barrel for the three months ended March 31, 2012. The decrease in the direct operating expenses per barrel of crude oil throughput is a function of the higher volume of throughput and lower overall expenses.

Operating Income. Petroleum operating income was $335.6 million for the three months ended March 31, 2013 as compared to operating income of $134.9 million for the three months ended March 31, 2012. This increase of $200.7 million was the result of an increase in the refining margin ($200.4 million) and a decrease in direct operating expenses ($6.7 million). The increase in refining margin and decrease in direct operating expense was partially offset by an increase in depreciation and amortization ($1.7 million) and an increase in selling, general and administrative expenses (exclusive of depreciation and amortization) ($4.7 million).

The tables below provide an overview of the nitrogen fertilizer business' results of operations, relevant market indicators and key operating statistics for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,

	2013			2012
Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(3)		111.4			89.3
Ammonia (net available for sale)(3)		30.7			25.0
UAN		196.2			154.6
Pet coke consumed (thousand tons)		129.8			120.5
Pet coke (cost per ton)	$	31		$	42
Sales (thousand tons)(4):
Ammonia		27.6			29.9
UAN		194.1			158.3
Product pricing (plant gate) (dollars per ton)(4):
Ammonia	$	663		$	613
UAN	$	295		$	313
On-stream factor(5):
Gasification		99.5	%		93.3	%
Ammonia		98.8	%		91.5	%
UAN		92.8	%		83.6	%
Reconciliation of net sales (dollars in millions):
Sales net plant gate	$	75.6		$	67.9
Freight in revenue		5.7			4.7
Hydrogen revenue		0.1			5.7

Total net sales	$	81.4		$	78.3

(1): Amounts are shown exclusive of depreciation and amortization.
(2): Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) depreciation and amortization and (iv) other income (expense). We present Adjusted Nitrogen Fertilizer EBITDA because it is a key measure used in material covenants in the Nitrogen Fertilizer Partnership's credit facility and because it is the starting point for the Nitrogen Fertilizer Partnership's available cash for distribution. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted EBITDA enables investors to better understand and evaluate the Nitrogen Fertilizer Partnership's ability to make distributions to the its common unitholders and its compliance with the covenants contained in the Nitrogen Fertilizer Partnership's credit facility. Adjusted Nitrogen Fertilizer EBITDA presented by other companies may not be comparable to our presentation, since each company may define those terms differently. Below is a reconciliation of operating income to Adjusted EBITDA for the nitrogen fertilizer segment for the three months ended March 31, 2013 and 2012:

(3): Gross tons produced for ammonia represent total ammonia, including ammonia produced that was upgraded into UAN. As a result of the recently completed UAN expansion project, we expect to upgrade substantially all of the ammonia we produce into UAN. The net tons available for sale represent ammonia available for sale that was not upgraded into UAN.
(4): Plant gate sales per ton represent net sales less freight costs and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.
(5): On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is a measure of operating efficiency. Excluding the impact of the downtime associated with the UAN expansion coming online, the on-stream factors for the three months ended March 31, 2013 would have been 99.5% for gasifier, 98.8% for ammonia and 98.3% for UAN.

Three Months Ended March 31, 2013 compared to the Three Months Ended March 31, 2012 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen Fertilizer net sales were $81.4 million for the three months ended March 31, 2013 compared to $78.3 million for the three months ended March 31, 2012. For the three months ended March 31, 2013, ammonia and UAN made up $18.7 million and $62.7 million of the nitrogen fertilizer business' net sales, respectively. This compared to ammonia and UAN net sales of $18.7 million and $53.9 million, respectively, for the three months ended March 31, 2012. The increase of $3.1 million was the result of higher UAN sales volumes ($12.2 million) and ammonia sales prices ($1.4 million) partially offset by lower hydrogen sales ($5.7 million) combined with lower UAN sales prices ($3.4 million) and decreased ammonia sales volumes ($1.4 million). The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the three months ended March 31, 2013 and March 31, 2012:

The increase in UAN sales volume for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily attributable to the UAN expansion coming online during the quarter. 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 99.5%, 98.8% and 92.8%, respectively, on-stream for the three months ended March 31, 2013. On-stream rates for the first quarter of 2012 were 93.3%, 91.5% and 83.6%, 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 March 31, 2013 compared to the three months ended March 31, 2012 increased 8.3% for ammonia and decreased 5.7% for UAN.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold exclusive of depreciation and amortization for the three months ended March 31, 2013 was $10.6 million, compared to $12.6 million for the three months ended March 31, 2012. The $2.0 million decrease resulted from $2.1 million in lower costs from transactions with third parties offset by higher costs from transactions with affiliates of $0.1 million. The decrease in costs was primarily the result of lower pet coke prices during the three months ended March 31, 2013.

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

environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the three months ended March 31, 2013 were $22.6 million as compared to $22.9 million for the three months ended March 31, 2012. The $0.3 million decrease resulted from lower property taxes ($2.7 million) partially offset by higher utilities ($0.7 million), labor ($0.6 million) and insurance ($0.5 million).

Operating Income. Nitrogen fertilizer operating income was $36.8 million for the three months ended March 31, 2013, as compared to operating income of $31.4 million for the three months ended March 31, 2012. The increase of $5.4 million for the three months ended March 31, 2013 as compared to the three months ended March 31, 2012 was the result of the increase in UAN sales volumes and ammonia sales prices ($3.1 million), decreased cost of product sold ($2.0 million), direct operating costs ($0.3 million), and selling, general and administrative expenses (exclusive of depreciation and amortization) ($0.4 million), partially offset by higher depreciation and amortization ($0.4 million).

Although results are consolidated for financial reporting, CVR Energy, CVR Refining and CVR Partners are independent business entities and operate with independent capital structures. Since the Nitrogen Fertilizer Partnership's IPO in April 2011, with the exception of cash distributions paid to us by the Nitrogen Fertilizer Partnership, the cash needs of the Nitrogen Fertilizer Partnership have been met independently from the cash needs of CVR Energy and the refining business with a combination of existing cash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. Prior to December 31, 2012, CVR Energy provided cash as needed to support the Refining Partnership's operations. Beginning January 1, 2013, CVR Energy and the Refining Partnership also operate with independent capital structures. The Refining Partnership's and the Nitrogen Fertilizer Partnerships' ability to generate sufficient cash flows from their respective operating activities and to then make distributions on their common units, including to us (which we will need to pay salaries, reporting expenses and other expenses as well as dividends on our common stock) will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.

We believe that the petroleum business and the nitrogen fertilizer business' cash flows from operations and existing cash and cash equivalents, along with borrowings under their respective existing credit facilities as necessary, will be sufficient to satisfy the anticipated cash requirements associated with their existing operations for at least the next twelve months, and that we have sufficient cash resources to fund our operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, the ability to generate sufficient cash from operating activities depends on future performance, which is subject to general economic, political, financial, competitive, and other factors.

As of March 31, 2013, we had consolidated cash and cash equivalents of $1,040.8 million. Of that amount, $362.5 million was cash and cash equivalents of CVR Energy, $525.1 million was cash and cash equivalents of the Refining Partnership and $153.2 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. During the three months ended March 31, 2013, our consolidated cash position increased approximately $144.8 million primarily as a result of increased operating and financing cash flows at the petroleum business, which was largely offset by the dividend payment in the first quarter of 2013. As of Apri1 30, 2013, we had consolidated cash and cash equivalents of approximately $1,092.8 million.

The Amended and Restated ABL Credit Facility provides the Refining Partnership with borrowing availability of up to $400.0 million with an incremental facility, subject to compliance with a borrowing base. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Refining Partnership and the credit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit. As of March 31, 2013, the Refining Partnership had $372.8 million available under the Amended and Restated ABL Credit Facility.

The Nitrogen Fertilizer 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. The Nitrogen Fertilizer Partnership credit facility matures in April 2016. The Nitrogen Fertilizer Partnership credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of March 31, 2013, the Nitrogen Fertilizer Partnership had $25.0 million available under the credit facility.

The Refining Partnership and Nitrogen Fertilizer Partnership have a distribution policy in which they will generally distribute all of their available cash each quarter, within 60 days after the end of each quarter for the Refining Partnership and 45 days after the end of each quarter for the Nitrogen Fertilizer Partnership. The Refining Partnership's distributions began with the quarter ending March 31, 2013 and have been adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO). The distributions will be made to all common unitholders. We currently hold approximately 81% and 70% of the Refining Partnership's and the Nitrogen Fertilizer Partnership's common units outstanding, respectively. The amount of each distribution will be determined pursuant to each general partner's calculation of available cash for the applicable quarter. The general partner of each partnership, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of each general partner's distribution policy, funds held by the Refining Partnership and the Nitrogen Fertilizer Partnership will not be available for our use, and we as a unitholder expect to receive our applicable percentage of the distribution of funds within 60 days or 45 days, respectively, following each quarter. The Refining Partnership and the Nitrogen Fertilizer Partnership do not have a legal obligation to pay distributions and there is no guarantee that they will pay any distributions on the units in any quarter.

2022 Notes. On October 23, 2012, Refining LLC and its wholly-owned subsidiary, Coffeyville Finance, issued $500.0 million aggregate principal amount of the 2022 Notes. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. The remaining proceeds from the offering were used to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of March 31, 2013, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.

The 2022 Notes were issued at 100% of their principal amount pursuant to an indenture (the "New Indenture"), dated October 23, 2012, among Refining LLC and Coffeyville Finance, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the "2022 Notes Trustee"). The Notes were fully and unconditionally guaranteed by CRLLC and substantially all of Refining LLC's subsidiaries (the "Guarantors" and, together with the Issuers, the "Credit Parties"). CRLLC was released as a guarantor in connection with the closing of the Refining Partnership's IPO on January 23, 2013, and CVR Refining subsequently became a guarantor. The obligations under the 2022 Notes and the related guarantees were initially secured by liens on substantially all of the assets of the issuers and the guarantors. The security interests were released upon satisfaction and discharge of the indenture governing the outstanding Second Lien Notes in connection with the closing of the Refining Partnership IPO.

The 2022 Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date.

The issuers have the right to redeem the 2022 Notes at a redemption price of (i) 103.250% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019 and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, in each case, plus any accrued and unpaid interest.

Prior to November 1, 2015, up to 35% of the 2022 Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus any accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.

In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 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 Refining LLC to any person other than qualifying owners (as defined in the indenture), (2) liquidation or dissolution of Refining LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stock of Refining LLC.

The indenture governing the 2022 Notes imposes covenants that restrict the ability of the issuers and guarantors to (i) issue 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 2022 Notes are rated investment grade by both Standard & Poor's Rating Services and Moody's Investors Services, Inc. However, such covenants would be reinstituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, or permit the trustee or the holders of at least 25% of the 2022 Notes to cause the acceleration of the 2022 Notes, in addition to the pursuit of other available remedies.

The indenture governing the 2022 Notes prohibits the Refining Partnership from making distributions to its unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the Refining Partnership's fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. We were in compliance with the covenants as of March 31, 2013.

Amended and Restated Asset Backed (ABL) Credit Facility. On December 20, 2012, CRLLC and certain subsidiaries (collectively, the "Credit Parties") entered into the Amended and Restated ABL Credit Facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced our ABL credit facility. Under the Amended and Restated ABL Credit Facility, the Refining Partnership assumed our position as borrower and our obligations under the Amended and Restated ABL Credit Facility upon the closing of the Refining Partnership IPO on January 23, 2013. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swing line loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The borrowing-base components, advance rates, prepayment provisions, collateral provisions, affirmative covenants and negative covenants in the Amended and Restated ABL Credit Facility are substantially similar to the corresponding provisions in the ABL credit facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and will be used for working capital and other general corporate purposes (including permitted acquisitions).

Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership is also required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.

The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The Amended and Restated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Refining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of March 31, 2013.

Old Notes. On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance completed the private offering of $275.0 million aggregate principal amount of First Lien Notes and $225.0 million aggregate principal amount of Second Lien 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 Old Notes at a purchase price of 103% of the outstanding principal amount. On December 15, 2011, we issued an additional $200.0 million aggregate principal amount of First Lien Notes to partially fund the acquisition of the Wynnewood refinery. The additional First Lien Notes were issued at 105% of their principal amount. On October 23, 2012, we repurchased approximately $323.0 million of our First Lien Notes pursuant to a tender offer and redeemed the remaining $124.1 million of outstanding First Lien Notes not tendered, on November 23, 2012, as discussed above. We redeemed all outstanding Second Lien Notes on January 23, 2013, following the closing of the Refining Partnership IPO, with a combination of proceeds from the Refining Partnership IPO and cash on hand.

Nitrogen Fertilizer Partnership Credit Facility. On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a credit facility (the "Nitrogen Fertilizer Partnership credit facility") with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership credit facility matures in April 2016.

Borrowings under the Nitrogen Fertilizer 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 Nitrogen Fertilizer 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 Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership and all of the capital stock of CRNF and each domestic subsidiary owned by the Nitrogen Fertilizer Partnership or CRNF. CRNF is the borrower under the Nitrogen Fertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility are unconditionally guaranteed by the Nitrogen Fertilizer 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 March 31, 2013, no amounts were drawn under the Nitrogen Fertilizer Partnership's $25.0 million revolving credit facility.

On June 30 and July 1, 2011, the Nitrogen Fertilizer Partnership's CRNF subsidiary entered into two Interest Rate Swap agreements with J. Aron & Company. These Interest Rate Swap agreements commenced on August 12, 2011. We have determined that the Interest Rate Swaps qualifies for hedge accounting treatment. The impact recorded for the months ended March 31, 2013 and 2012 is $0.3 million and $0.2 million, respectively, in interest expense. For the three months ended March 31, 2013 and 2012, the Nitrogen Fertilizer Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $46,000 and $0.2 million, respectively, which is unrealized in accumulated other comprehensive income.

We divide the petroleum business and the nitrogen fertilizer business' 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 three months ended March 31, 2013 by operating segment and major category:

	Three Months Ended March 31, 2013

	(in millions)
Petroleum Business (the Refining Partnership):
Coffeyville refinery:
Maintenance	$	10.4
Growth		0.2

Coffeyville refinery total capital		10.6
Wynnewood refinery:
Maintenance		31.5
Growth		1.5

Wynnewood refinery total capital		33.0
Other Petroleum:
Maintenance		1.0
Growth		—

Other petroleum total capital		1.0

Petroleum business total capital		44.6

Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
Maintenance		0.6
Growth		17.5

Nitrogen fertilizer business total capital		18.1

Corporate		1.0

Total capital spending	$	63.7

Including amounts already spent during the three months ended March 31, 2013, the petroleum business expects to spend, in total, approximately $250.0 million to $270.0 million (excluding capitalized

interest) on capital expenditures for the year ending December 31, 2013. Of this amount $105.0 million to $115.0 million is expected to be spent for the Coffeyville refinery which includes approximately $90.0 million to $95.0 million of maintenance capital. Approximately $125.0 million to $135.0 million is expected to be spent on capital for the Wynnewood refinery which includes approximately $95.0 million to $105.0 million of maintenance capital. We also expect to spend $20.0 million on other petroleum capital projects and approximately $2.0 million associated with corporate related projects.

Including amounts already spent during the three months ended March 31, 2013, the nitrogen fertilizer business expects to spend, in total, $43.0 million to $53.0 million on capital expenditures for the year ending December 31, 2013 (excluding capitalized interest). Of this amount, $7.0 million to $9.0 million will be spent on maintenance projects and $36.0 million to $44.0 million will be spent on growth projects including approximately $23.0 million on the UAN expansion project.

In February 2013, the nitrogen fertilizer business completed a significant two-year plant expansion designed to increase its UAN production capacity by 400,000 tons, or approximately 50% per year. The expansion was at full operating rates prior to the end of the first quarter. The UAN expansion provides the nitrogen fertilizer business with the ability to upgrade substantially all of its ammonia production to UAN. The nitrogen fertilizer business anticipates the total capital spend associated with the UAN expansion will approximate $130.0 million, excluding capitalized interest. As of March 31, 2013, approximately $120.2 million had been spent, including $14.1 million which was spent during the three months ended March 31, 2013.

In January 2013, the nitrogen fertilizer business completed the UAN terminal project which included the construction of a two million gallon UAN storage tank and related truck and railcar load-out facilities located in Phillipsburg, Kansas. The property on which this terminal was constructed is owned by a subsidiary of CVR Refining, Coffeyville Resources Terminal, LLC, which operates the terminal. The purpose of the UAN terminal is to distribute approximately 20,000 tons of UAN fertilizer annually.

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 provided by operating activities for the three months ended March 31, 2013 were $278.3 million. The positive cash flow from operating activities generated over this period was primarily driven by $212.7 million of net income before noncontrolling interest and non-cash adjustments for depreciation and amortization ($34.2 million), loss on extinguishment of debt ($26.1 million) and

deferred income taxes ($21.4 million), partially offset by an unrealized gain on derivatives ($32.5 million). This positive net income was primarily due to the higher operating margins for the period. Unfavorable changes in trade working capital during the three months ended March 31, 2013 were largely offset by favorable changes in other working capital. Trade working capital for the three months ended March 31, 2013 resulted in a cash outflow of $102.0 million which was primarily attributable to an increase in accounts receivable ($72.9 million) and a decrease in accounts payable ($32.1 million). Other working capital activities resulted in net cash inflow of $111.4 million and were primarily related to an increase in due to parent ($66.4 million), an increase in deferred revenue ($27.6 million) and an increase in other current liabilities ($19.5 million).

Net cash flows used for operating activities for the three months ended March 31, 2012 were $186.3 million. The positive cash flow used for operating activities was primarily driven by operating income of $140.5 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 three months ended March 31, 2012 resulted in a cash in-flow of $32.4 million, primarily as a result of an increase in accounts payable of $49.8 million coupled with a reduction of inventory of $46.1 million and offset by an increase in accounts receivable of $63.5 million. Other working capital activities of $9.5 million was primarily driven by an increase in other current liabilities of $21.2 million partially offset by a decrease in prepaid expenses and other current assets of $13.8 million.

Net cash used in investing activities for the three months ended March 31, 2013 was $63.7 million compared to $59.4 million for the three months ended March 31, 2012. The increase in cash used in investing activities was primarily the result of an increase in capital expenditures of $4.2 million. The petroleum business' capital expenditures increased $9.1 million for the three months ended March 31, 2013 compared to the same period in 2012 due to projects at the Wynnewood refinery. This increase was offset by a decrease in nitrogen fertilizer capital expenditures of $4.2 million primarily related to decreased capital expenditures for the UAN expansion, which was completed in February 2013.

Net cash used in financing activities for the three months ended March 31, 2013 was approximately $69.8 million as compared to $14.4 million for three months ended March 31, 2012. The net cash used in financing activities for the three months ended March 31, 2013 was primarily attributable to dividend payments to common stockholders of $477.6 million, payments to extinguish the Second Lien Notes of $243.4 million and distributions to noncontrolling interest holders at the Nitrogen Fertilizer Partnership of $4.3 million, largely offset by proceeds from CVR Refining's initial public offering of $655.7 million.

Net cash used in financing activities for the three months ended March 31, 2012 was primarily attributable a cash distribution to noncontrolling interest holders of the Nitrogen Fertilizer Partnership of $13.0 million. Additionally, financing costs of approximately $1.1 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.

For the three months ended March 31, 2013, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility. As of March 31, 2013, there were no short-term borrowings outstanding under the Amended and Restated 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 March 31, 2013 relating to long-term debt outstanding on that date, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following March 31, 2013 and thereafter. As of March 31, 2013, there were no amounts outstanding under the Amended and Restated ABL Credit Facility or the revolving facility under the Nitrogen Fertilizer Partnership's credit facility.

	Payments Due by Period

	Total		2013		2014		2015		2016		2017		Thereafter
	(in millions)
Contractual Obligations
Long-term debt(1)	$	625.0	$	—	$	—	$	—	$	125.0	$	—	$	500.0
Operating leases(2)		37.0		7.5		7.9		6.5		5.6		3.0		6.5
Capital lease obligations(3)		52.0		0.8		1.3		1.4		1.6		1.8		45.1
Unconditional purchase obligations(4)		1,418.0		92.2		110.1		99.2		92.2		90.9		933.4
Environmental liabilities(5)		2.4		0.5		0.3		0.2		0.2		0.1		1.1
Interest payments(6)		395.0		40.6		42.3		42.1		38.6		37.1		194.3

Total	$	2,529.4	$	141.6	$	161.9	$	149.4	$	263.2	$	132.9	$	1,680.4
Other Commercial Commitments
Standby letters of credit(7)	$	27.2	$	—	$	—	$	—	$	—	$	—	$	—

(1): Consists of the 2022 Notes and the Nitrogen Fertilizer Partnership's term loan facility outstanding on March 31, 2013.
(2): The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under 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 associated with the acquisition of the Wynnewood refinery.
(4): The amount includes (a) commitments under several agreements for the 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 and (d) a pet coke supply agreement with HollyFrontier Corporation having an initial term that ends in December 2013, subject to renewal and (e) approximately $993.9 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011.
(5): Environmental liabilities represents (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."

The Refining Partnership's and the Nitrogen Fertilizer Partnership's ability to make payments on and to refinance their indebtedness, to fund budgeted capital expenditures and to satisfy their other capital and commercial commitments will depend on their respective independent abilities to generate cash flow in the future. Their ability to refinance their respective indebtedness is also subject to the availability of the credit markets. This, to a certain extent, is subject to refining spreads (for the Refining Partnership), fertilizer margins (for the Nitrogen Fertilizer Partnership) and general economic financial, competitive, legislative, regulatory and other factors they are unable to control. Our businesses may not generate sufficient cash flow from operations, and future borrowings may not be available to the Nitrogen Fertilizer Partnership under its revolving credit facility, or the Refining Partnership under the Amended and Restated ABL Credit Facility (or other credit facilities our businesses may enter into in the future) in an amount sufficient to enable them to pay indebtedness or to fund other liquidity needs. They may seek to sell assets to fund liquidity needs but may not be able to do so. They may also need to refinance all or a portion of their indebtedness on or before maturity, and may not be able to refinance such indebtedness on commercially reasonable terms or at all.

We had no off-balance sheet arrangements as of March 31, 2013, as defined within the rules and regulations of the SEC.

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 GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities" ("ASU 2013-01"). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. We adopted these standards as of January 1, 2013. The adoption of these standards expanded our condensed consolidated financial statement footnote disclosures.

In February 2013, the FASB issued ASU No. 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" ("ASU 2013-02"). ASU 2013-02 requires us to present information about reclassification adjustments from accumulated other comprehensive income in our financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification. The standard is effective for interim and annual periods beginning January 1, 2013 and is to be applied prospectively. We adopted this standard as of January 1, 2013. The adoption of this standard did not materially 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, 2012. 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 three months ended March 31, 2013 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, 2012. 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 March 31, 2013, the Refining Partnership had open commodity hedging instruments consisting of 22.8 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at March 31, 2013 was a net unrealized loss of $34.1 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 commodity hedging instruments of $22.8 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 the nitrogen fertilizer business' $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays 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 March 31, 2013, the effective rate was approximately 4.58%.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.

The Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership by approximately $625,000 on an annualized basis, thus decreasing the Refining Partnership's net income by the same amount.

As of March 31, 2013, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. 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 to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information 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 March 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See Note 11 ("Commitments and Contingencies") to Part I, Item I of this Report, which is incorporated by reference into this Part II, Item 1, for a description of the litigation, legal and administrative proceedings and environmental matters.

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, 2012.

		Exhibit Title

4.1	**	Registration Rights Agreement, dated as of January 23, 2013, by and among CVR Refining, LP, Icahn Enterprises Holdings L.P., CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).

10.1	**	First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).

10.2	**	Trademark License Agreement, dated as of January 23, 2013, by and among CVR Refining, LP and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).

10.3	**	CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by CVR Refining, LP on January 23, 2013 (Commission File No. 001-35781)).

10.4	**	Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and among CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).

10.5	**	Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 23, 2013 (Commission File No. 001-35781)).

10.6	*	Amendment to Third Amended and Restated Employment Agreement, dated as of March 11, 2013, by and between CVR Energy, Inc. and John J. Lipinski.

31.1	*	Certification of the Company's Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.

31.2	*	Certification of the Company's Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act.

32.1	*	Certification of the Company's Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	*	Certification of the Company's Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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 March 31, 2013
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 o		Accelerated filer ý		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—March 31, 2013 (unaudited) and December 31, 2012	6
	Condensed Consolidated Statements of Operations—Three Months Ended March 31, 2013 and 2012 (unaudited)	7
	Condensed Consolidated Statements of Comprehensive Income (Loss)—Three Months Ended March 31, 2013 and 2012 (unaudited)	8
	Condensed Consolidated Statement of Changes in Equity—Three Months Ended March 31, 2013 (unaudited)	9
	Condensed Consolidated Statements of Cash Flows—Three Months Ended March 31, 2013 and 2012 (unaudited)	10
	Notes to the Condensed Consolidated Financial Statements—March 31, 2013 (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	83
Item 4.	Controls and Procedures	84
Part II. Other Information
Item 1.	Legal Proceedings	85
Item 1A.	Risk Factors	85
Item 6.	Exhibits	85
Signatures		87

			Weighted-Average Grant-Date Fair Value

Non-vested at January 1, 2013	1,145,611		$	23.24
Granted	—			—
Vested	(3,198	)		27.51
Forfeited	(1,666	)		17.24

Non-vested at March 31, 2013	1,140,747		$	23.24

		Weighted-Average Grant-Date Fair Value

Non-vested at January 1, 2013	201,812	$	23.70
Granted	—		—
Vested	—		—
Forfeited	—		—

Non-vested at March 31, 2013	201,812	$	23.70

	March 31, 2013		December 31, 2012

	(in thousands)
Finished goods	$	264,237	$	275,169
Raw materials and precious metals		161,492		164,287
In-process inventories		54,310		42,767
Parts and supplies		45,066		45,847

	$	525,105	$	528,070

	March 31, 2013		December 31, 2012

	(in thousands)
10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1,840 as of December 31, 2012	$	—	$	220,910
6.5% Senior Notes, due 2022		500,000		500,000
CRNF credit facility		125,000		125,000
Capital lease obligations		50,884		51,168

Long-term debt	$	675,884	$	897,078

	For the Three Months Ended March 31,

	2013		2012
	(in thousands, except share data)
Net income (loss) attributable to CVR Energy stockholders	$	165,033	$	(25,202	)
Weighted-average shares of common stock outstanding—Basic		86,831,050		86,808,150
Weighted-average shares of common stock outstanding—Diluted		86,831,050		86,808,150
Basic earnings (loss) per share	$	1.90	$	(0.29	)
Diluted earnings (loss) per share	$	1.90	$	(0.29	)

	Operating Leases		Unconditional Purchase Obligations(1)

	(in thousands)
Nine months ending December 31, 2013	$	7,511	$	92,210
Year ending December 31, 2014		7,914		110,122
Year ending December 31, 2015		6,492		99,206
Year ending December 31, 2016		5,616		92,165
Year ending December 31, 2017		2,965		90,886
Thereafter		6,547		933,392

	$	37,045	$	1,417,981

	Amount

	(in thousands)
Nine months ending December 31, 2013	$	533
Year Ending December 31,
2014		340
2015		190
2016		132
2017		114
Thereafter		1,068

Undiscounted total		2,377
Less amounts representing interest at 1.62%		219

Accrued environmental liabilities at March 31, 2013	$	2,158

	As of March 31, 2013

Description	Gross Non- Current Assets		Gross Amounts Offset			Net Non- Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in thousands)
Commodity Swaps	$	1,463	$	(2	)	$	1,461	$	—	$	1,461

Total	$	1,463	$	(2	)	$	1,461	$	—	$	1,461

	As of March 31, 2013

Description	Gross Current Liabilities		Gross Amounts Offset			Net Current Liabilities Presented		Cash Collateral Not Offset			Net Amount
	(in thousands)
Commodity Swaps	$	54,588	$	(19,058	)	$	35,530	$	—		$	35,530
Other Derivative Activity		251		—			251		(251	)		—

Total	$	54,839	$	(19,058	)	$	35,781	$	(251	)	$	35,530

	As of March 31, 2013		As of December 31, 2012

	(unaudited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	1,040.8	$	896.0
Working capital		1,283.2		1,135.4
Total assets		3,772.1		3,610.9
Total debt, including current portion		677.0		898.2
Total CVR Energy stockholders' equity		1,441.7		1,525.2

	Three Months Ended March 31,

	2013		2012
	(unaudited) (dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Refining margin(4)	$	26.71	$	20.07
Gross profit(3)		20.20		11.15
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2)		4.91		6.95
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6)		4.64		6.51
Barrels sold (barrels per day)(6)		205,875		156,573

	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012

													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		9.6	$	118.30	$	1,136.8		8.2	$	120.37	$	981.5		1.4	$	155.3	$	(19.9	)	$	175.2
Distillate		7.8	$	130.44	$	1,023.4		6.2	$	131.21	$	811.6		1.6	$	211.8	$	(6.0	)	$	217.8

	Three Months Ended March 31,

	2013		2012
Market Indicators
Natural gas NYMEX (dollars per MMBtu)	$	3.48	$	2.50
Ammonia—Southern Plains (dollars per ton)		696		586
UAN—Mid Corn belt (dollars per ton)		378		343

	Three Months Ended March 31, 2013						Three Months Ended March 31, 2012						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		27,572	$	679	$	18.7		29,866	$	627	$	18.7		(2,294	)	$	—		$	1.4		$	(1.4	)
UAN		194,141	$	323	$	62.7		158,293	$	340	$	53.9		35,848		$	8.8		$	(3.4	)	$	12.2
Hydrogen		2,713	$	11	$	—		562,657	$	10	$	5.7		(559,944	)	$	(5.7	)	$	—		$	(5.7	)

Number			Exhibit Title

	101	*	The following financial information for CVR Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, filed with the SEC on May 2, 2013, 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) and (6) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail.***.


	CVR Energy, Inc.
May 2, 2013	By:	/s/ JOHN J. LIPINSKI Chief Executive Officer (Principal Executive Officer)
May 2, 2013	By:	/s/ SUSAN M. BALL Chief Financial Officer (Principal Financial and Accounting Officer)