SEC Filing | CVR Energy, Inc.

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CVI Q3 2013 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

OR

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission file number: 001-33492

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)



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)

(281) 207-3200

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant 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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” 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 þ

There were 86,831,050 shares of the registrant’s common stock outstanding at October 29, 2013.

CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2013



		Page No.
Part I. Financial Information
Item 1.	Financial Statements	6

	Condensed Consolidated Balance Sheets — September 30, 2013 (unaudited) and December 31, 2012	6

	Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	7

	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	8

	Condensed Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2013 (unaudited)	9

	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2013 and 2012 (unaudited)	10

	Notes to the Condensed Consolidated Financial Statements — September 30, 2013 (unaudited)	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	76

Item 4.	Controls and Procedures	77

Part II. Other Information

Item 1.	Legal Proceedings	79

Item 1A.	Risk Factors	79

Item 6.	Exhibits	80

Signatures		81

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GLOSSARY OF SELECTED TERMS

The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the quarter ended September 30, 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.

distillates — Primarily diesel fuel, kerosene and jet fuel.

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.

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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.

MSCF— One thousand standard cubic feet, a customary gas measurement unit.

natural gas liquids — Natural gas liquids, often referred to as NGLs, are feedstocks used in the manufacture of refined fuels, as well as 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 common units representing limited partner interests of CVR Refining, LP (the “Refining Partnership”), which closed on January 23, 2013 (which includes the underwriters’ subsequently-exercised option to purchase additional common units).

Secondary Offering — The registered public offering of 12,000,000 common units representing limited partner interests of the Nitrogen Fertilizer Partnership, which closed on May 28, 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.

Underwritten Offering — The underwritten offering of 13,209,236 common units of the Refining Partnership, which closed on May 20, 2013 (which includes the underwriters’ subsequently-exercised option to purchase additional common units).

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.

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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.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,			December 31,
	2013			2012
	(unaudited)
	(in millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	887.1		$	896.0
Accounts receivable, net of allowance for doubtful accounts of $2.6 and $2.0, respectively	240.9			210.6
Inventories	680.3			528.1
Prepaid expenses and other current assets	142.5			54.4
Insurance receivable	—			1.3
Income tax receivable	3.1			4.1
Deferred income taxes	14.5			57.4
Due from parent	—			9.2
Total current assets	1,968.4			1,761.1
Property, plant, and equipment, net of accumulated depreciation	1,834.7			1,782.9
Intangible assets, net	0.3			0.3
Goodwill	41.0			41.0
Deferred financing costs, net	11.9			16.6
Insurance receivable	4.0			4.0
Other long-term assets	14.8			5.0
Total assets	$	3,875.1		$	3,610.9
LIABILITIES AND EQUITY
Current liabilities:
Note payable and capital lease obligations	$	1.2		$	1.1
Accounts payable	394.7			440.1
Personnel accruals	53.8			51.2
Accrued taxes other than income taxes	21.6			36.7
Due to parent	33.7			—
Deferred revenue	0.8			1.0
Other current liabilities	67.4			95.6
Total current liabilities	573.2			625.7
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion	675.2			897.1
Accrued environmental liabilities, net of current portion	1.4			1.6
Deferred income taxes	610.5			386.9
Other long-term liabilities	48.0			39.5
Total long-term liabilities	1,335.1			1,325.1
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 September 30, 2013 and December 31, 2012	0.9			0.9
Additional paid-in-capital	1,114.9			582.3
Retained earnings	163.4			945.4
Treasury stock, 98,610 as of September 30, 2013 and December 31, 2012, at cost	(2.3		)	(2.3		)
Accumulated other comprehensive loss, net of tax	(0.7		)	(1.2		)
Total CVR stockholders’ equity	1,276.2			1,525.1
Noncontrolling interest	690.6			135.0
Total equity	1,966.8			1,660.1
Total liabilities and equity	$	3,875.1		$	3,610.9

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(unaudited)
	(in millions, except per share data)
Net sales	$	1,977.1		$	2,409.6		$	6,549.8		$	6,686.5
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)	1,744.4			1,702.5			5,343.5			5,211.9
Direct operating expenses (exclusive of depreciation and amortization)	128.4			109.9			345.2			319.5
Selling, general and administrative expenses (exclusive of depreciation and amortization)	27.7			30.4			85.0			147.7
Depreciation and amortization	36.2			33.1			105.4			97.4
Total operating costs and expenses	1,936.7			1,875.9			5,879.1			5,776.5
Operating income	40.4			533.7			670.7			910.0
Other income (expense):
Interest expense and other financing costs (Note 13)	(11.7		)	(18.9		)	(39.6		)	(57.1		)
Interest income	0.3			0.3			0.9			0.5
Gain (loss) on derivatives, net	72.5			(168.9		)	173.0			(277.4		)
Loss on extinguishment of debt	—			—			(26.1		)	—
Other income (expense), net	6.2			(0.1		)	6.5			0.8
Total other income (expense)	67.3			(187.6		)	114.7			(333.2		)
Income before income taxes	107.7			346.1			785.4			576.8
Income tax expense	29.5			127.6			222.8			209.0
Net income	78.2			218.5			562.6			367.8
Less: Net income attributable to noncontrolling interest	34.2			9.6			170.2			29.4
Net income attributable to CVR Energy stockholders	$	44.0		$	208.9		$	392.4		$	338.4

Basic earnings per share	$	0.51		$	2.41		$	4.52		$	3.90
Diluted earnings per share	$	0.51		$	2.41		$	4.52		$	3.86

Weighted-average common shares outstanding:
Basic	86.8			86.8			86.8			86.8
Diluted	86.8			86.8			86.8			87.6

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(unaudited) (in millions)
Net income	$	78.2		$	218.5		$	562.6		$	367.8
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $1.5, $0, $2.4 and $0	2.3			—			3.7			—
Net gain reclassified into income on sale of available-for-sale securities, net of tax of $(2.4), $0, $(2.4) and $0 (Note 12)	(3.7		)	—			(3.7		)	—
Change in fair value of interest rate swap, net of tax of $(0.1), $(0.1), $0 and $(0.3)	(0.2		)	(0.3		)	(0.1		)	(1.0		)
Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.1, $0.1, $0.2 and $0.2 (Note 13)	0.3			0.2			0.6			0.5
Total other comprehensive income (loss)	(1.3		)	(0.1		)	0.5			(0.5		)
Comprehensive income	76.9			218.4			563.1			367.3
Less: Comprehensive income attributable to noncontrolling interest	34.2			9.5			170.4			29.1
Comprehensive income attributable to CVR Energy stockholders	$	42.7		$	208.9		$	392.7		$	338.2

See accompanying notes to the condensed consolidated financial statements.

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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 millions, except share data)
Balance at December 31, 2012	86,929,660	$	0.9	$	582.3		$	945.4		$	(2.3	)	$	(1.2	)	$	1,525.1		$	135.0		$	1,660.1
January issuance of CVR Refining’s common units to the public, net of $148.0 tax impact	—	—		229.3			—			—			—			229.3			276.4			505.7
May issuance of CVR Refining’s common units to the public, net of $96.0 tax impact	—	—		148.9			—			—			—			148.9			148.7			297.6
Sale of CVR Refining’s common units to affiliate, net of $15.2 tax impact	—	—		23.6			—			—			—			23.6			22.7			46.3
Secondary offering of CVR Partners’ common units to the public, net of $88.5 tax impact	—	—		129.7			—			—			0.2			129.9			74.1			204.0
Dividends paid to CVR Energy stockholders	—	—		—			(1,172.2		)	—			—			(1,172.2		)	—			(1,172.2		)
Distributions from CVR Partners to public unitholders	—	—		—			—			—			—			—			(37.7		)	(37.7		)
Distributions from CVR Refining to public unitholders	—	—		—			—			—			—			—			(101.4		)	(101.4		)
Share-based compensation	—	—		1.2			(2.2		)	—			—			(1.0		)	2.5			1.5
Redemption of common units	—	—		(0.1		)	—			—			—			(0.1		)	(0.1		)	(0.2		)
Net income	—	—		—			392.4			—			—			392.4			170.2			562.6
Net gain on interest rate swaps, net of tax	—	—		—			—			—			0.3			0.3			0.2			0.5
Balance at September 30, 2013	86,929,660	$	0.9	$	1,114.9		$	163.4		$	(2.3	)	$	(0.7	)	$	1,276.2		$	690.6		$	1,966.8

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2013			2012
	(unaudited)
	(in millions)
Cash flows from operating activities:
Net income	$	562.6		$	367.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	105.4			97.4
Allowance for doubtful accounts	0.6			0.6
Amortization of deferred financing costs	2.2			5.9
Amortization of original issue discount	—			0.4
Amortization of original issue premium	—			(2.6		)
Deferred income taxes	(72.1		)	13.8
Loss on disposition of assets	—			1.1
Loss on extinguishment of debt	26.1			—
Share-based compensation	13.7			28.5
Gain on sale of available-for-sale securities	(6.1		)	—
(Gain) loss on derivatives, net	(173.0		)	277.4
Current period settlements on derivative contracts	(3.9		)	(80.4		)
Changes in assets and liabilities:
Accounts receivable	(30.9		)	(98.0		)
Inventories	(152.2		)	111.9
Prepaid expenses and other current assets	11.0			13.7
Insurance receivable	1.3			(0.3		)
Other long-term assets	(0.4		)	0.8
Accounts payable	(21.3		)	(42.8		)
Due to parent	42.9			44.4
Accrued income tax	1.0			40.7
Deferred revenue	(0.2		)	1.3
Other current liabilities	14.8			2.3
Accrued environmental liabilities	(0.2		)	(0.1		)
Net cash provided by operating activities	321.3			783.8
Cash flows from investing activities:
Capital expenditures	(183.6		)	(145.0		)
Proceeds from sale of assets	0.1			0.4
Insurance proceeds for UAN reactor rupture	—			1.0
Purchase of available-for-sale securities	(18.6		)	—
Proceeds from sale of available-for-sale securities	24.7			—
Net cash used in investing activities	(177.4		)	(143.6		)
Cash flows from financing activities:
Payment of capital lease obligations	(0.9		)	(0.8		)
Payments on senior secured notes	(243.4		)	—
Payment of financing costs	(0.4		)	(2.0		)
Proceeds from CVR Refining’s initial public offering in January, net of offering costs	655.7			—
Proceeds from CVR Refining’s offering in May, net of offering costs	393.6			—
Proceeds from the sale of CVR Refining’s common units to affiliate	61.5			—
Proceeds from CVR Partners’ secondary offering, net of offering costs	292.6			—
Exercise of stock options	—			0.4
Redemption of common units	(0.2		)	(0.1		)
Dividends to CVR Energy’s stockholders	(1,172.2		)	—
Distributions to CVR Refining’s noncontrolling interest holders	(37.7		)	—
Distributions to CVR Partners’ noncontrolling interest holders	(101.4		)	(37.8		)
Net cash used in financing activities	(152.8		)	(40.3		)
Net (decrease) increase in cash and cash equivalents	(8.9		)	599.9



Cash and cash equivalents, beginning of period	896.0			388.3
Cash and cash equivalents, end of period	$	887.1		$	988.2
Supplemental disclosures:
Cash paid for income taxes, net of refunds	$	251.1		$	109.9
Cash paid for interest net of capitalized interest of $2.0 and $7.1 in 2013 and 2012, respectively	$	36.6		$	37.2
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	$	32.0		$	31.7
Change in accounts payable related to construction in process additions	$	(24.2	)	$	1.9

See accompanying notes to the condensed consolidated financial statements

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

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

Organization

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 UAN and ammonia. 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 September 30, 2013, IEP owned approximately 82% of all of the outstanding shares of CVR. 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").

CVR Partners, LP

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 and through May 27, 2013.

On May 28, 2013, Coffeyville Resources, LLC (“CRLLC”) completed a registered public offering (the “Secondary Offering”) whereby it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period.

Subsequent to the closing of the Secondary Offering and as of September 30, 2013, public security holders held approximately 47% of the total outstanding Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of the total Nitrogen Fertilizer Partnership common units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer Partnership’s general partner, CVR GP, LLC, which only holds a non-economic general partner interest. The 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.

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 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.

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September 30, 2013

(unaudited)

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.

CVR Refining, LP

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 the initial public offering of its common units representing limited partner interests (the “Refining Partnership IPO”). The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00 per unit. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00 per common unit in connection with the underwriters’ exercise of their option to purchase additional common units. 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. 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.

On May 20, 2013, the Refining Partnership completed an underwritten offering (the “Underwritten Offering”) by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation (“AEPC”), an affiliate of Icahn Enterprises LP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the “Transactions.”

Subsequent to the closing of the Transactions and as of September 30, 2013, public security holders held approximately 29% of the total Refining Partnership common units (including units owned by affiliates of Icahn Enterprises representing 4% of the total Refining Partnership common units), and CVR Refining Holdings held approximately 71% of the total Refining Partnership common units. In addition, CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy, owns 100% of the Refining Partnership’s general partner, CVR Refining GP, LLC, which holds a non-economic general partner interest. The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Refining Partnership.

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.

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September 30, 2013

(unaudited)

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.

Basis of Presentation

The accompanying condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (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, the Refining Partnership and their respective subsidiaries. The ownership interests of noncontrolling investors in CVR’s 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 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 general partners of the Nitrogen Fertilizer Partnership and the Refining Partnership 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 66 2/3% 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 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 September 30, 2013 and December 31, 2012, the results of operations and comprehensive income for the three and nine month periods ended September 30, 2013 and 2012, changes in equity for the nine month period ended September 30, 2013 and cash flows of the Company for the nine month periods ended September 30, 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 ending 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.

(2) Recent Accounting Pronouncements

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September 30, 2013

(unaudited)

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.

In July 2013, the FASB issued ASU No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” (“ASU 2013-11”). ASU 2013-11 requires the netting of unrecognized tax benefits against a deferred tax asset for a loss or other carryforward that would apply in settlement of the uncertain tax positions. The standard is effective for interim and annual periods beginning after December 15, 2013 and is to be applied prospectively with optional retrospective adoption permitted. The adoption of this standard is effective on January 1, 2014. The Company is currently evaluating the standard but does not expect it to materially impact the condensed consolidated financial statements and footnote disclosures.

(3) Share-Based Compensation

Long-Term Incentive Plan – CVR Energy

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 September 30, 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 authorized 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.

Restricted Shares

A summary of restricted stock units grant activity and changes during the nine months ended September 30, 2013 is presented below:



	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2013	1,145,611		$	23.24
Granted	2,600		54.75
Vested	(184,952	)	7.99
Forfeited	(15,089	)	22.76
Non-vested at September 30, 2013	948,170		$	26.31

Through the LTIP, restricted shares have been granted to employees of the Company. Prior to the change of control as discussed in Note 1 ("Organization and History of the Company and Basis of Presentation"), 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.

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September 30, 2013

(unaudited)

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 non-transferable contingent cash payment (“CCP”) upon vesting. The CCPs expired on August 19, 2013. 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. As a result of the modification, additional share-based compensation of approximately $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the nine months ended September 30, 2012. 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-classified awards to liability-classified awards.

In December 2012 and subsequent periods, restricted stock units were granted to certain employees of CVR. The non-vested restricted stock units are scheduled to vest over three years, with one-third of the award vesting each year on the anniversary of the grant date, 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. As such, no expense related to this discretionary award was recorded during the three and nine months ended September 30, 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 September 30, 2013, there was approximately $8.2 million of total unrecognized compensation cost related to restricted stock units and associated dividends to be recognized over a weighted-average period of approximately 0.7 years. Total compensation expense for the three months ended September 30, 2013 and 2012 was approximately $3.0 million and $6.0 million, respectively, related to the LTIP. Total compensation expense for the nine months ended September 30, 2013 and 2012 was approximately $12.1 million and $26.8 million, respectively, related to the LTIP. As of September 30, 2013 and December 31, 2012, the Company had a liability of $26.1 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.

Long-Term Incentive Plan – CVR Partners

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, (3) members of the board of directors of its general partner and (4) employees, consultants and directors of CVR Energy. 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 that 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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

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 nine months ended September 30, 2013 is presented below:



	Units		Weighted‑Average Grant-Date Fair Value
Non-vested at January 1, 2013	201,812		$	23.70
Granted	—		—
Vested	(21,158	)	20.09
Forfeited	—		—
Non-vested at September 30, 2013	180,654		$	24.12

As of September 30, 2013, there was approximately $1.6 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of one year. Compensation expense recorded for the three months ended September 30, 2013 and 2012 related to the awards under the CVR Partners LTIP was approximately $0.4 million and $0.5 million, respectively. Compensation expense recorded for each of the nine months ended September 30, 2013 and 2012 related to the awards under the CVR Partners LTIP was approximately $1.6 million. As of September 30, 2013 and December 31, 2012, the Company has a liability of $0.4 million and $0.2 million, respectively, for unvested phantom unit awards, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

Long-Term Incentive Plan – CVR Refining

In connection with the Refining Partnership IPO, on January 16, 2013, the board of directors of the general partner of the Refining Partnership 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 its 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. On August 14, 2013, the Refining Partnership filed a Form S-8 to register the common units. As of September 30, 2013, no awards have been granted under the plan.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

(4) Inventories

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.

Inventories consisted of the following:



	September 30, 2013		December 31, 2012
	(in millions)
Finished goods	$	362.4	$	275.2
Raw materials and precious metals	194.6		164.3
In-process inventories	78.5		42.8
Parts and supplies	44.8		45.8
	$	680.3	$	528.1

(5) Property, Plant, and Equipment

A summary of costs for property, plant, and equipment is as follows:



	September 30, 2013		December 31, 2012
	(in millions)
Land and improvements	$	34.0	$	31.0
Buildings	42.5		40.6
Machinery and equipment	2,284.8		2,089.5
Automotive equipment	16.7		15.0
Furniture and fixtures	14.7		13.7
Leasehold improvements	2.5		2.5
Aircraft	2.2		—
Railcars	8.0		2.5
Construction in progress	134.8		189.2
	2,540.2		2,384.0
Accumulated depreciation	705.5		601.1
Total property, plant and equipment, net	$	1,834.7	$	1,782.9

Capitalized interest recognized as a reduction in interest expense for the three months ended September 30, 2013 and 2012 totaled approximately $0.8 million and $2.8 million, respectively. Capitalized interest recognized as a reduction in interest expense for the nine months ended September 30, 2013 and 2012 totaled approximately $2.0 million and $7.1 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1 million as of September 30, 2013 and December 31, 2012. Amortization of assets held under capital leases is included in depreciation expense.

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September 30, 2013

(unaudited)

(6) Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense, renewable identification numbers (“RINs”) expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.3 million and $1.0 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, cost of product sold excludes depreciation and amortization of approximately $3.7 million and $2.6 million, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately $34.0 million and $31.6 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, direct operating expenses exclude depreciation and amortization of approximately $99.8 million and $93.1 million, 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 $0.9 million and $0.5 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.9 million and $1.7 million, respectively.

(7) Income Taxes

On May 19, 2012, CVR became a member of the consolidated federal tax group of 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 September 30, 2013, the Company has recorded a liability of $33.7 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended September 30, 2013 and 2012, the Company paid $95.0 million and $65.1 million, respectively, for estimated federal income tax payments due to AEPC under the Tax Allocation Agreement. For the nine months ended September 30, 2013 and 2012, the Company paid $234.0 million and $65.1 million, respectively, for estimated federal income tax payments 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 September 30, 2013, the Company had unrecognized tax benefits of approximately $44.8 million, of which $18.8 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 $2.0 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 September 30, 2013, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2010 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 and nine months ended September 30, 2013 was 27.4% and 28.4%, respectively, 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 and nine months ended September 30, 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 and state income tax credits. The Company’s effective tax rate for the three and nine months ended September 30, 2012 was 36.9% and 36.2%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 39.4%. The Company’s effective tax rate for the three and nine months ended September 30, 2012

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September 30, 2013

(unaudited)

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.

(8) Long-Term Debt

Long-term debt was as follows:



	September 30, 2013		December 31, 2012
	(in millions)
10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1.8 million as of December 31, 2012	$	—	$	220.9
6.5% Senior Notes, due 2022	500.0		500.0
CRNF credit facility	125.0		125.0
Capital lease obligations	50.2		51.2
Long-term debt	$	675.2	$	897.1

Senior Secured Notes

On April 6, 2010, CRLLC and its then wholly‑owned subsidiary, Coffeyville Finance (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 “2010 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 2010 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 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” and together with the 2010 First Lien Notes, the “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 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 nine months ended September 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

2022 Senior Secured 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. 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, which occurred on January 23, 2013. The 2022 Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC’s existing domestic subsidiaries on a joint and several basis. CVR

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Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. 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 Energy, 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 redeem 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 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. On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership incurred approximately $0.1 million and $0.4 million of debt registration costs related to the registration and exchange offer during the three and nine months ended September 30, 2013, respectively, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method.

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 contain 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 certain payments on contractually subordinated 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 has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of September 30, 2013, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.

At September 30, 2013, the estimated fair value of the 2022 Notes was approximately $485.6 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.

Amended and Restated Asset Backed (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 prior ABL credit facility, 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

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million subject to receipt of 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 September 30, 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 prior 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 September 30, 2013, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.9 million and had letters of credit outstanding of approximately $27.1 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of September 30, 2013.

Nitrogen Fertilizer Partnership Credit Facility

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 September 30, 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

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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 September 30, 2013, CRNF was in compliance with the covenants contained in the credit facility and there were no borrowings outstanding under the credit facility.

Capital Lease Obligations

As a result of the acquisition of the Wynnewood refinery, the Refining Partnership 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 193 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 192 months remaining and will expire in September 2029.

(9) Dividends

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 quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which the Company began paying in the second quarter of 2013. Additionally, the Company declared and paid two special cash dividends during the nine months ended September 30, 2013.

The following is a summary of the quarterly and special dividends paid to stockholders during the nine months ended September 30, 2013:



	February 19, 2013		May 17, 2013		June 10, 2013		August 19, 2013		Total Dividends Paid in 2013
	(in millions, except per share amounts)
Dividend type	Special		Quarterly		Special		Quarterly
Amount paid to IEP	$	391.6	$	53.4	$	462.8	$	53.4	$	961.2
Amounts paid to public stockholders	86.0		11.7		101.6		11.7		211.0
Total amount paid	$	477.6	$	65.1	$	564.4	$	65.1	$	1,172.2
Per common share	$	5.50	$	0.75	$	6.50	$	0.75	$	13.50
Shares outstanding	86.8		86.8		86.8		86.8

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(10) Earnings Per Share

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions, except per share data)
Net income attributable to CVR Energy stockholders	$	44.0	$	208.9	$	392.4	$	338.4
Weighted-average number of shares of common stock outstanding	86.8		86.8		86.8		86.8
Effect of dilutive securities:
Non-vested common stock	—		—		—		0.8
Stock options	—		—		—		—
Weighted-average number of shares of common stock outstanding assuming dilution	86.8		86.8		86.8		87.6
Basic earnings per share	$	0.51	$	2.41	$	4.52	$	3.90
Diluted earnings per share	$	0.51	$	2.41	$	4.52	$	3.86

All outstanding stock options totaling 22,900 were exercised in May 2012. There were no dilutive awards outstanding during the three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2013, as all unvested awards under the LTIP were liability-classified awards. See Note 3 (“Share-Based Compensation”).

(11) Commitments and Contingencies

Leases and Unconditional Purchase Obligations

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



	Operating Leases		Unconditional Purchase Obligations(1)
	(in millions)
Three Months Ending December 31, 2013	$	2.4	$	85.3
Year Ending December 31,
2014	9.3		113.1
2015	7.9		101.4
2016	6.8		94.2
2017	4.2		93.0
Thereafter	8.2		953.7
	$	38.8	$	1,440.7

(1)

This amount includes approximately $965.5 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. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

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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 September 30, 2013 and 2012, lease expense totaled approximately $2.4 million and $1.2 million, respectively. For the nine months ended September 30, 2013 and 2012, lease expense totaled approximately $7.0 million and $3.9 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.

Crude Oil Supply Agreement

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. 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 the expiration of the Initial Term or any Renewal Term.

Litigation

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.

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 September 30, 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 September 30, 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 and among Gary-Williams, CRLLC, and the escrow agent, dated as of December 15, 2011. Gary-

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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, 2008 through 2012. The Kansas Court of Appeals, in a memorandum opinion dated August 9, 2013, reversed the COTA decision in part and remanded the case to COTA, instructing COTA to classify each asset on an asset by asset basis instead of making a broad determination that the entire plant was real property as COTA did originally. CRNF believes that when that asset by asset determination is done, the majority of the plant will be classified as personal property which would result in significantly lower property taxes for CRNF for 2008 and for those years after the conclusion of the property tax settlement noted below as compared to the taxes paid by CRNF prior to the settlement. The County has filed a motion for rehearing with the Kansas Court of Appeals seeking reconsideration of the Court’s August 9, 2013 decision and that motion was denied. The County also filed a petition for review with the Kansas Supreme Court and that petition is pending.

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 discussed above.

Flood, Crude Oil Discharge and Insurance

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 May 2008, in connection with the discharge, the Company received 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 reached an agreement with the DOJ resolving its claims under the CWA and the OPA. The agreement is memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 and March 25, 2013, respectively (the “2013 Consent Decree”). On April 19, 2013, CRRM paid a civil penalty (including accrued interest) in the amount of $0.6 million for the 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 reached an agreement to settle DOJ’s RMP claims, which was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively, and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP settlement agreement.

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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.

Environmental, Health, and Safety (“EHS”) Matters

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 governmental oversight costs arising from oil spills into waters of the United States, which has been broadly interpreted to include virtually any water bodies including intermittent streams and water bodies.

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 September 30, 2013 and December 31, 2012, environmental accruals of approximately $1.8 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 $0.4 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 September 30, 2013 and December 31, 2012, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million for two landfills at both September 30, 2013 and December 31, 2012. The estimated future payments for these required obligations are as follows:

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	Amount
	(in millions)
Three Months Ending December 31, 2013	$	0.2
Year Ending December 31,
2014	0.4
2015	0.2
2016	0.1
2017	0.1
Thereafter	1.1
Undiscounted total	2.1
Less amounts representing interest at 2.34%	0.3
Accrued environmental liabilities at September 30, 2013	$	1.8

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 companies to lose small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Total capital expenditures to comply with the rule are expected to be approximately $63.0 million for CRRM and $105.0 million for WRC. As of September 30, 2013, approximately $19.1 million and $35.4 million had been spent related to these projects by CRRM and WRC, respectively.

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 fuel credits, known as 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. On August 6, 2013, the EPA announced the final 2013 renewable fuel percentage standard would be raised to 9.74%. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its transportation fuel or purchase RINs in lieu of blending, and in 2013, the Wynnewood refinery will be required to comply, unless the Wynnewood refinery receives relief from the rule in 2013 based on the "disproportionate economic impact" of the rule on the Wynnewood refinery. 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. The cost of RINs for the three and nine month periods ended September 30, 2012 was approximately $7.1 million and $16.5 million, respectively, and the cost of RINs for the three and nine month periods ended September 30, 2013 was approximately $57.4 million and $155.0 million, respectively. As of September 30, 2013 and December 31, 2012, the petroleum business’ biofuel blending obligation was approximately $47.5 million and $1.1 million, respectively, which was recorded in other current liabilities on the Condensed Consolidated Balance Sheets. The ultimate cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business’ petroleum products, as well as the fuel blending performed at the its refineries, all of which can vary significantly from quarter to quarter.

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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 alleged 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 requiring the payment of civil penalties and the installation of air 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 $40.0 million. 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 entered into a Consent Order with the Oklahoma Department of Environmental Quality (the "ODEQ") in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certain historic Clean Air Act compliance issues related to the operations of the refinery by the prior owner. 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 in 2012. The remaining costs are expected to be approximately $3.0 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, ODEQ conducts inspections of the Wynnewood refinery and identifies areas of alleged noncompliance. ODEQ routinely pursues enforcement related to the alleged noncompliance seeking civil penalties and injunctive relief, which may necessitate the installation of controls. ODEQ has advised the company that it is preparing to issue a full compliance evaluation report covering the period from 2010 through 2013. The agency has indicated that it will pursue enforcement related to the alleged noncompliance and that it expects to enter into a second Consent Order with the Company, which would necessitate the payment of a civil penalty and the implementation of injunctive relief to address the alleged noncompliance. The costs of any such enforcement action cannot be predicted at this time. However, based on our experience related to Clean Air Act enforcement and control requirements, the Company does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.

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.

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From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company’s compliance with 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.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended September 30, 2013 and 2012, capital expenditures were approximately $35.5 million and $7.7 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. For the nine months ended September 30, 2013 and 2012, capital expenditures were approximately $73.5 million and $18.7 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 Company's business, financial condition, or results of operations.

Wynnewood Refinery Incident

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 cooperated with OSHA in its investigation. 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 is vigorously contesting the citations and OSHA’s placement of WRC in the SVEP. Any penalties associated with OSHA’s citations are not expected to have a material adverse effect on the condensed consolidated financial statements. On September 25, 2013, WRC agreed to pay a small civil penalty to settle rather than defend claims alleged by the EPA under the Clean Air Act's general duty clause related to the boiler incident. In addition to the above, the spouses of the two employees fatally injured have filed a civil lawsuit against WRC, CVR Refining and CVR Energy in Fort Bend County, Texas. The civil suit is in its preliminary stages and it is currently too early to assess a potential outcome.

Affiliate Pension Obligations

Mr. Icahn, through certain affiliates, owns approximately 82% of the Company’s capital stock. Applicable pension and tax laws make each member of a “controlled group” of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due may result in the creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of the controlled group.

As a result of the more than 80% ownership interest in CVR Energy by Mr. Icahn's affiliates, the Company is subject to the pension liabilities of all entities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. One such entity, ACF Industries LLC (“ACF”), is the sponsor of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of September 30, 2013. If the ACF plans were voluntarily terminated, they would be underfunded by approximately $116.9 million as of September 30, 2013. As a result of Mr. Icahn's affiliates obtaining approximately 80.7% of the outstanding common stock of Federal-Mogul Corporation (“Federal Mogul”) during the three months ended September 30, 2013, the Company is also subject to the pension liabilities of Federal-Mogul. If the plans of Federal-Mogul and ACF were voluntarily terminated, as of September 30, 2013, they would collectively be underfunded by approximately $702.9 million. These results are based on the most recent information provided by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the

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(unaudited)

assumptions used to calculate the liability. As members of the controlled group, CVR Energy would be liable for any failure of ACF and Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes CVR Energy may have pension plan obligations that are, or may become, underfunded, and the Company would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain “reportable events,” such as if CVR Energy were to cease to be a member of the controlled group, or if CVR Energy makes certain extraordinary dividends or stock redemptions. The obligation to report could cause the Company to seek to delay or reconsider the occurrence of such reportable events. Based on the contingent nature of potential exposure related to these affiliate pension obligations, no liability has been recorded in the condensed consolidated financial statements.

(12) Fair Value Measurements

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:


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


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


•	Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of September 30, 2013 and December 31, 2012:



	September 30, 2013
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Cash equivalents	$	81.0	$	—		$	—	$	81.0
Other current assets (other derivative agreements)	—		101.9			—		101.9
Other long-term assets (other derivative agreements)	—		8.2			—		8.2
Total Assets	$	81.0	$	110.1		$	—	$	191.1
Other current liabilities (interest rate swap)	—		(0.9		)	—		(0.9		)
Other long-term liabilities (interest rate swap)	—		(1.2		)	—		(1.2		)
Total Liabilities	$	—	$	(2.1	)	$	—	$	(2.1	)

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(unaudited)



	December 31, 2012
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Cash equivalents	$	134.0	$	—		$	—	$	134.0
Other long-term assets (other derivative agreements)	—		0.9			—		0.9
Total Assets	$	134.0	$	0.9		$	—	$	134.9
Other current liabilities (other derivative agreements)	—		(67.7		)	—		(67.7		)
Other current liabilities (interest rate swap)	—		(0.9		)	—		(0.9		)
Other current liabilities (biofuel blending obligation)	—		(1.1		)	—		(1.1		)
Other long-term liabilities (interest rate swap)	—		(1.9		)	—		(1.9		)
Total Liabilities	$	—	$	(71.6	)	$	—	$	(71.6	)

As of September 30, 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, derivative instruments and the uncommitted biofuel blending obligation. 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 the uncommitted biofuel blending obligation which use fair value measurements are valued using broker quoted market prices of similar instruments which are considered Level 2 inputs. As of September 30, 2013, the Refining Partnership's biofuel blending obligation was fully committed. 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. During the three months ended September 30, 2013, the Company received proceeds of $24.7 million for the sale of its investments in marketable securities, which were previously classified as available-for-sale and reported at fair market value using quoted market prices. The aggregate cost basis for the available-for-sale securities sold was approximately $18.6 million. Upon the sale of the available-for-sale securities, the Company reclassified the unrealized gain of $6.1 million from accumulated other comprehensive income and recognized a realized gain in other income for the three and nine months ended September 30, 2013. As of September 30, 2013, the Company does not hold any further investments in available-for-sale securities. The Company had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2013.

(13) Derivative Financial Instruments

Gain (loss) on derivatives, net and current period settlements on derivative contracts were as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
	(in millions)
Current period settlements on derivative contracts	$	33.9	$	(53.2	)	$	(3.9	)	$	(80.4	)
Gain (loss) on derivatives, net	$	72.5	$	(168.9	)	$	173.0		$	(277.4	)

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 (gain) loss on derivatives, net in the

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(unaudited)

Condensed Consolidated Statements of Operations. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.

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 September 30, 2013 was an immaterial net loss included in other current liabilities. For the three months ended September 30, 2013 and 2012, the Refining Partnership recognized a net gain of $0.1 million and a net loss of $7.1 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the nine months ended September 30, 2013 and 2012, the Refining Partnership recognized net losses of $2.3 million and $11.0 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

Commodity Swap

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 September 30, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 20.6 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 September 30, 2013 was a net unrealized gain of $110.1 million, of which $101.9 million is included in current assets and $8.2 million is included in non-current assets. For the three months ended September 30, 2013 and 2012, the Refining Partnership recognized a net gain of $72.4 million and a net loss of $161.8 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the nine months ended September 30, 2013 and 2012, the Refining Partnership recognized a net gain of $175.3 million and a net loss of $266.4 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

Nitrogen Fertilizer Partnership Interest Rate Swap

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. See Note 8 (“Long-Term Debt”). 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 will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements 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 September 30, 2013, the effective rate was approximately 4.57%. 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 the three months ended September 30, 2013 and 2012, respectively. For the three months ended September 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized a decrease in the fair value of the interest rate swap agreements of $0.3 million and $0.4 million, respectively, which was unrealized in AOCI. The realized loss on the interest rate swap re-classed from AOCI into interest expense and other

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financing costs on the Condensed Consolidated Statements of Operations was $0.8 million and $0.7 million for the nine months ended September 30, 2013 and 2012. For the nine months ended September 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized a decrease in the fair value of the interest rate swap agreements of $0.1 million and $1.3 million, respectively, which was unrealized in AOCI.

Counterparty Credit Risk

The Refining Partnership’s exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The Refining Partnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Condensed Consolidated Balance Sheets. As of September 30, 2013, the counterparty credit risk adjustment was not material to the condensed consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.

Offsetting Assets and Liabilities

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 September 30, 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 September 30, 2013 are recorded as current assets and non-current assets in prepaid expenses and other current assets and other long-term assets, respectively, in the Condensed Consolidated Balance Sheets as follows:



	As of September 30, 2013
Description	Gross Current Assets		Gross Amounts Offset			Net Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	104.1	$	(2.2	)	$	101.9	$	—	$	101.9
Total	$	104.1	$	(2.2	)	$	101.9	$	—	$	101.9

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(unaudited)



	As of September 30, 2013
Description	Gross Non-Current Assets		Gross Amounts Offset		Net Non-Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	8.2	$	—	$	8.2	$	—	$	8.2
Total	$	8.2	$	—	$	8.2	$	—	$	8.2

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:



	As of December 31, 2012
Description	Gross Non-Current Assets		Gross Amounts Offset		Net Non-Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	0.9	$	—	$	0.9	$	—	$	0.9
Total	$	0.9	$	—	$	0.9	$	—	$	0.9



	As of December 31, 2012
Description	Gross Current Liabilities		Gross Amounts Offset			Net Current Liabilities Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	74.2	$	(6.5	)	$	67.7	$	—	$	67.7
Total	$	74.2	$	(6.5	)	$	67.7	$	—	$	67.7

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(14) Related Party Transactions

Icahn Acquisition

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 September 30, 2013, IEP owned approximately 82% of all common shares outstanding.

Lease

From March 2009 through June 2013, the Company, through the Nitrogen Fertilizer Partnership, leased 199 railcars from American Railcar Leasing LLC (“ARL”), a company controlled by Mr. Carl Icahn, the Company’s majority stockholder. The agreement was scheduled to expire on March 31, 2014. On June 13, 2013, the Nitrogen Fertilizer Partnership purchased the railcars under the lease from ARL for approximately $5.0 million. For the three months ended September 30, 2013 and 2012, $0 and $0.3 million, respectively, of rent expense was recorded related to this agreement and is included in cost of product sold (exclusive of depreciation and amortization) in the Condensed Consolidated Statements of Operations. For the nine months ended September 30, 2013 and 2012, rent expense of $0.4 million and $0.8 million, respectively, was recorded related to this agreement.

International Truck Purchase

During the three months ended September 30, 2013, the Refining Partnership purchased seven trucks from a subsidiary of Navistar International Corporation ("Navistar") for approximately $0.8 million. Mr. Icahn, the Company's majority stockholder, indirectly owns approximately 17% of Navistar's outstanding common stock.

Tax Allocation Agreement

As of September 30, 2013, the Company has recorded approximately $33.7 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended September 30, 2013 and 2012, the Company paid $95.0 million and $65.1 million, respectively, for estimated federal income tax payments due to AEPC under the Tax Allocation Agreement. During the nine months ended September 30, 2013 and 2012, the Company paid $234.0 million and $65.1 million, respectively, for estimated federal income tax payments due to AEPC under the Tax Allocation Agreement.

Insight Portfolio Group

Insight Portfolio Group LLC (“Insight Portfolio Group”) is an entity formed 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 million and $0.1 million during the three and nine months ended September 30, 2013, respectively. 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.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

(15) Business Segments

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.

Petroleum

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 $1.6 million and $2.4 million for the three months ended September 30, 2013 and 2012, respectively. Intercompany sales included in petroleum net sales were approximately $7.0 million and $7.3 million for the nine months ended September 30, 2013 and 2012, respectively.

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the net hydrogen purchases (sales) described below under “Nitrogen Fertilizer” of approximately $0.8 million and $0.2 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, the Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) of approximately $4.7 million and $5.8 million, respectively. The Petroleum Segment recorded intercompany revenue for hydrogen sales of approximately $0.3 million and $0 for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, the Petroleum Segment recorded intercompany revenue of approximately $0.6 million and $0, respectively.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $2.2 million and $2.5 million for the three months ended September 30, 2013 and 2012 respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $7.4 million and $7.8 million for the nine months ended September 30, 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 September 30, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $0.8 million and $0.3 million, respectively. For the nine months ended September 30, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $4.7 million and $6.0 million, respectively. For the three months ended September 30, 2013 and 2012, the nitrogen fertilizer segment also recognized approximately $0.3 million and $0.1 million, respectively, of cost of product sold related to the transfer of excess hydrogen. For the nine months ended September 30, 2013 and 2012, the Nitrogen Fertilizer Segment also recognized approximately $0.6 million and $0.2 million, respectively, of cost of product sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

Other Segment

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Net sales
Petroleum	$	1,910.5		$	2,337.3		$	6,322.6		$	6,465.3
Nitrogen Fertilizer	69.2			75.0			239.4			234.7
Intersegment elimination	(2.6		)	(2.7		)	(12.2		)	(13.5		)
Total	$	1,977.1		$	2,409.6		$	6,549.8		$	6,686.5
Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,734.7		$	1,694.0		$	5,317.0		$	5,190.8
Nitrogen Fertilizer	13.0			11.3			39.2			34.6
Intersegment elimination	(3.3		)	(2.8		)	(12.7		)	(13.5		)
Total	$	1,744.4		$	1,702.5		$	5,343.5		$	5,211.9
Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	104.7		$	88.8		$	274.5		$	253.1
Nitrogen Fertilizer	23.7			21.1			70.7			66.4
Other	—			—			—			—
Total	$	128.4		$	109.9		$	345.2		$	319.5
Depreciation and amortization
Petroleum	$	28.8		$	27.5		$	85.2		$	80.4
Nitrogen Fertilizer	6.6			5.2			18.5			15.8
Other	0.8			0.4			1.7			1.2
Total	$	36.2		$	33.1		$	105.4		$	97.4
Operating income
Petroleum	$	23.4		$	507.5		$	588.1		$	891.2
Nitrogen Fertilizer	21.3			32.3			95.2			99.8
Other	(4.3		)	(6.1		)	(12.6		)	(81.0		)
Total	$	40.4		$	533.7		$	670.7		$	910.0
Capital expenditures
Petroleum	$	60.7		$	20.2		$	140.8		$	82.8
Nitrogen fertilizer	4.0			18.2			35.8			57.4
Other	4.3			1.5			7.0			4.8
Total	$	69.0		$	39.9		$	183.6		$	145.0

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)



	As of September 30,		As of December 31,
	2013		2012
	(in millions)
Total assets
Petroleum	$	2,686.5	$	2,258.5
Nitrogen Fertilizer	594.0		623.0
Other	594.6		729.4
Total	$	3,875.1	$	3,610.9
Goodwill
Petroleum	$	—	$	—
Nitrogen Fertilizer	41.0		41.0
Other	—		—
Total	$	41.0	$	41.0

(16) Subsequent Events

Dividend

On October 31, 2013, the board of directors of the Company declared a cash dividend for the third 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 November 18, 2013 to stockholders of record at the close of business on November 11, 2013. IEP will receive $53.4 million in respect of its 82% ownership interest in the Company’s shares.

Nitrogen Fertilizer Partnership Distribution

On October 31, 2013, the board of directors of the Nitrogen Fertilizer Partnership’s general partner declared a cash distribution for the third quarter of 2013 to the Nitrogen Fertilizer Partnership’s unitholders of $0.36 per common unit, or $26.3 million in aggregate. The cash distribution will be paid on November 18, 2013 to unitholders of record at the close of business on November 11, 2013. The Company will receive $14.0 million in respect of its Nitrogen Fertilizer Partnership common units.

Refining Partnership Distribution

On October 31, 2013, the board of directors of the Refining Partnership’s general partner declared a cash distribution for the third quarter of 2013 to the Refining Partnership’s unitholders of $0.30 per common unit, or $44.3 million in aggregate. The cash distribution will be paid on November 18, 2013 to unitholders of record at the close of business on November 11, 2013. The Company will receive $31.4 million in respect of its Refining Partnership common units.

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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 and nine months ended September 30, 2013 are not necessarily indicative of results to be attained for any other period.

Forward-Looking Statements

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:


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


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


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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in 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:


•	change in control;


•	volatile margins in the refining industry;


•	exposure to the risks associated with volatile crude oil prices;


•	the availability of adequate cash and other sources of liquidity for our capital needs;


•	our ability to forecast our future financial condition or results of operations and our future revenues and expenses;


•	disruption of our ability to obtain an adequate supply of crude oil;


•	interruption of the pipelines supplying feedstock and in the distribution of our products;


•	competition in the petroleum and nitrogen fertilizer businesses;


•	capital expenditures and potential liabilities arising from environmental laws and regulations;


•	changes in our credit profile;


•	the cyclical nature of the nitrogen fertilizer business;


•	the seasonal nature of the petroleum business;


•	the supply and price levels of essential raw materials;


•	the risk of a material decline in production at our refineries and nitrogen fertilizer plant;

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•	potential operating hazards from accidents, fire, severe weather, floods or other natural disasters;


•	the risk associated with governmental policies affecting the agricultural industry;


•	the volatile nature of ammonia, potential liability for accidents involving ammonia that cause interruption to our businesses, severe damage to property and/or injury to the environment and human health and potential increased costs relating to the transport of ammonia;


•	the dependence of the nitrogen fertilizer operations on a few third-party suppliers, including providers of transportation services and equipment;


•	new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities;


•	our dependence on significant customers;


•	the potential loss of the nitrogen fertilizer business’ transportation cost advantage over its competitors;


•	our potential inability to successfully implement our business strategies, including the completion of significant capital programs;


•	our ability to continue to license the technology used in our operations;


•	our petroleum business’ ability to purchase gasoline and diesel RINs on a timely and cost effective basis;


•	our petroleum business’ continued ability to secure environmental and other governmental permits necessary for the operation of our business;


•	existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and existing and future regulations related to the end-use and application of fertilizers;


•	refinery and nitrogen fertilizer facility operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage;


•	instability and volatility in the capital and credit markets; and


•	potential exposure to underfunded pension obligations of affiliates as a member of the controlled group of Mr. Icahn.

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, except as may be required by law.

Company Overview

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 UAN and ammonia. 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. At September 30, 2013, we owned the general partner and approximately 71% 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

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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 WTS, WTI, sweet and sour Canadian and other U.S. domestically produced crude oils. The petroleum business expects to spend approximately $60.0 million on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. As of September 30, 2013, approximately $16.3 million has been spent on the Wynnewood hydrocracker project. 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 third quarter of 2013 was $1.25 per barrel compared to $4.38 per barrel in the third quarter of 2012.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At September 30, 2013, we owned the general partner and approximately 53% 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 and nine months ended September 30, 2013, the nitrogen fertilizer business produced 100,360 and 303,030 tons of ammonia, respectively, of which approximately 98% and 90% was upgraded into 239,258 and 660,581 tons of UAN, respectively.

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 in February 2013 designed to increase its UAN production capacity by 400,000 tons, or approximately 50%, per year. 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.

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Transaction Agreement

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 was executed on or before August 18, 2013 and such transaction closed. As no sale of the Company was executed by the date outlined in the Transaction Agreement, the CCPs expired on August 19, 2013.

In May 2012, IEP acquired a majority of the common stock of CVR Energy through the Offer. As of September 30, 2013, IEP owned approximately 82% of CVR Energy's outstanding common stock.

Refining Partnership Initial Public Offering

On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00 per common unit, resulting in gross proceeds of $600.0 million. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00 per common unit in connection with the exercise of the underwriters’ option to purchase additional common units, 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 and through May 19, 2013, CVR Energy indirectly owned 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.

Refining Partnership Underwritten Offering

On May 20, 2013, the Refining Partnership completed the Underwritten Offering by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation (“AEPC”), an affiliate of Icahn Enterprises LP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with the exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the “Transactions.”

Following the closing of the Transactions and as of September 30, 2013, public security holders held approximately 29% of all outstanding Refining Partnership common units (including units held by affiliates of Icahn Enterprises, representing approximately 4% of all outstanding Refining Partnership common units), and CVR Refining Holdings held approximately 71% of all outstanding Refining Partnership common units in addition to owning 100% of CVR Refining GP, LLC, the general partner.

The Refining Partnership utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters’ option) to redeem 13,209,236 common units from CVR Refining Holdings. The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.

Nitrogen Fertilizer Partnership Secondary Offering

On May 28, 2013, Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, completed the Secondary Offering in which it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC.

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Following the closing of the Secondary Offering and as of September 30, 2013, public security holders held approximately 47% of all outstanding Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of all outstanding Nitrogen Fertilizer Partnership common units in addition to owning 100% of CVR GP, LLC, the general partner.

Major Influences on Results of Operations

Petroleum Business

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 fuel 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. On August 6, 2013, the EPA announced the final 2013 renewable fuel percentage standard would be raised to 9.74%. In 2013, the Wynnewood refinery will be subject to the RFS for the first time, unless the Wynnewood refinery receives relief from the rule in 2013 based on the "disproportionate economic impact" of the rule on the Wynnewood refinery, and the cost of RINs became extremely volatile and significantly higher than the cost during the comparable 2012 period. The cost of RINs for the year ended December 31, 2012 was approximately $21.0 million. The cost of RINs for the three and nine months ended September 30, 2012 was approximately $7.1 million and $16.5 million, respectively, and the cost of RINs for the three and nine months ended September 30, 2013 was approximately $57.4 million and $155.0 million, respectively. The ultimate cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business’ petroleum products, as well as the fuel blending performed at its refineries, all of which can vary significantly from quarter to quarter. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business estimates that the total cost of RINs will be approximately $175.0 million to $190.0 million for the year ending December 31, 2013.

If sufficient RINs are unavailable for purchase at times when the petroleum business seeks to purchase RINs, or if the petroleum business has to pay a significantly 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. Many petroleum refiners blend renewable fuel into their transportation fuels and do not have to pass on the costs of compliance through the purchase of RINs to their customers. Therefore, it may be significantly harder for the petroleum business to pass on the costs of compliance with RFS to its customers.

Because the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year, the Wynnewood refinery has petitioned the EPA as a “small refinery” for hardship relief from the RFS requirements in 2013 and 2014.

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

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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 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 nine months ended September 30, 2013, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $6.3 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 its 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.

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Nitrogen Fertilizer Business

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 and nine months ended September 30, 2013, the nitrogen fertilizer business upgraded approximately 98% and 90%, respectively, 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 in February 2013, the nitrogen fertilizer business now upgrades 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 the petroleum business and third parties. In the three and nine months ended September 30, 2013, the nitrogen fertilizer business spent approximately $3.5 million and $10.9 million, respectively, for pet coke, which equaled an average cost per ton of $30 for both periods. In the three and nine months ended September 30, 2012, the nitrogen fertilizer business spent approximately $3.8 million and $12.9 million, respectively, for pet coke, which equaled an average cost per ton of $30 and $34, 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 and on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN

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(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 Nitrogen Fertilizer Partnership is planning to defer the next full facility turnaround to 2015. It is anticipated that a less involved facility shutdown will be performed mid-year 2014 to upgrade the pressure swing absorption unit, which is projected to increase hydrogen recovery sufficient to produce approximately 7,000 to 8,000 tons of additional ammonia fertilizer annually.

Agreements With the Refining Partnership and the Nitrogen Fertilizer Partnership

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.

Crude Oil Supply Agreement

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. 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 the expiration of the Initial Term or any Renewal Term.

Factors Affecting Comparability

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.

Transaction Expenses

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 $44.2 million for the nine months ended September 30, 2012 that did not occur in 2013. No amounts were incurred in the three months ended September 30, 2013 or 2012. We are currently challenging a

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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.

New and Refinanced Indebtedness

Notes. In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, Inc. (“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 voluntarily redeemed $27.5 million of 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 $200.0 million of 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 nine months ended September 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

Share-Based Compensation

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. The CCPs expired on August 19, 2013. 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. As a result of the modification, additional share-based compensation of $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the nine months ended September 30, 2012. 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 September 30, 2013 and 2012, we incurred compensation expense of $3.0 million and $6.0 million, respectively, related to non-vested share-based compensation awards related to the LTIP. For the nine months ended September 30, 2013 and 2012, we incurred compensation expense of $12.1 million and $26.8 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

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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. For the three months ended September 30, 2013 and 2012, we incurred compensation expense of $0.4 million and $0.5 million, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP. For each of the nine months ended September 30, 2013 and 2012, we incurred compensation expense of $1.6 million related to non-vested share-based compensation awards related to the CVR Partners LTIP.

Noncontrolling Interest

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 was impacted additionally by the noncontrolling ownership percentage of the net income of the Refining Partnership and related distributions for each future reporting period. As a result of the Refining Partnership’s closing of the Underwritten Offering to sell an additional 13,209,236 common units to the public (including 1,209,236 units purchased through the underwriters’ option) and the sale of 2,000,000 common units to AEPC, the noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the Transactions in the second quarter of 2013 and as of September 30, 2013 is approximately 29%. Additionally, as a result of the Secondary Offering to sell 12,000,000 Nitrogen Fertilizer Partnership common units, the noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the Secondary Offering on May 28, 2013 and as of September 30, 2013 is approximately 47%.

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 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.

Publicly Traded Partnership Expenses

We expect 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.

Fluid Catalytic Cracking Unit (“FCCU”) Outage

During the three months ended September 30, 2013, the FCCU at the Refining Partnership’s Coffeyville refinery was offline for approximately 55 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at the Coffeyville refinery was significantly reduced during the three months ended September 30, 2013. Additionally, the Refining Partnership incurred approximately $20.8 million in costs to repair the FCCU during the three months ended September 30, 2013. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Condensed Consolidated Statements of Operations.

Turnaround Projects

The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery incurred costs of approximately $21.2 million for the nine months ended September 30, 2012 associated with the 2011/2012 turnaround. The Wynnewood refinery incurred turnaround costs of approximately $13.4 million for the three and nine months ended September 30, 2012 related to the turnaround, which was completed during the fourth quarter of 2012.

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Wynnewood Transaction Fees and Integration Expenses

As a result of the acquisition of the Wynnewood refinery in December 2011, we incurred transaction fees and integration expenses for the three and nine months ended September 30, 2012 of $2.0 million and $10.3 million, respectively. We did not incur such expenses for the three and nine months ended September 30, 2013 as the Wynnewood refinery’s operations were fully integrated.

Fertilizer Plant Property Taxes

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, 2008 through 2012. The Kansas Court of Appeals, in a memorandum opinion dated August 9, 2013, reversed the COTA decision in part and remanded the case to COTA, instructing COTA to classify each asset on an asset by asset basis instead of making a broad determination that the entire plant was real property as COTA did originally. CRNF believes that when that asset by asset determination is done, the majority of the plant will be classified as personal property which would result in significantly lower property taxes for CRNF for 2008 and for those years after the conclusion of the property tax settlement noted below as compared to the taxes paid by CRNF prior to the settlement. The County has filed a motion for rehearing with the Kansas Court of Appeals seeking reconsideration of the Court’s August 9, 2013 decision and that motion was denied. The County also filed a petition for review with the Kansas Supreme Court and that petition is pending.

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 discussed above.

Distributions to CVR Partners Unitholders

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 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.

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The following is a summary of cash distributions paid to the Nitrogen Fertilizer Partnership unitholders during 2013 for the respective quarters to which the distributions relate:



	December 31, 2012		March 31, 2013		June 30, 2013		Total Cash Distributions Paid in 2013
	($ in millions, expect per common unit amounts)
Amount paid to CRLLC	$	9.8	$	31.1	$	22.7	$	63.5
Amounts paid to public unitholders	4.2		13.5		19.9		37.7
Total amount paid	$	14.0	$	44.6	$	42.6	$	101.2
Per common unit	$	0.192	$	0.610	$	0.583	$	1.385
Common units outstanding	73.1		73.1		73.1

On October 31, 2013, the board of directors of the Nitrogen Fertilizer Partnership’s general partner declared a cash distribution for the third quarter of 2013 to the Nitrogen Fertilizer Partnership’s unitholders of $0.36 per common unit or $26.3 million in aggregate. The cash distribution will be paid on November 18, 2013 to unitholders of record at the close of business on November 11, 2013. We will receive $14.0 million in respect of our common units.

Distributions to CVR Refining Unitholders

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, and other excess cash, 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.

The following is a summary of cash distributions paid to the Refining Partnership unitholders during 2013 for the respective quarters to which the distributions relate:



	March 31, 2013⁽¹⁾		June 30, 2013		Total Cash Distributions Paid in 2013
	($ in millions, expect per common unit amounts)
Amount paid to CVR Refining Holdings, LLC	$	189.6	$	141.5	$	331.1
Amounts paid to public unitholders	43.6		57.8		101.4
Total amount paid	$	233.2	$	199.3	$	432.5
Per common unit	$	1.58	$	1.35	$	2.93
Common units outstanding	147.6		147.6


(1)	The distribution for the period ended March 31, 2013 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 October 31, 2013, the board of directors of the Refining Partnership’s general partner declared a cash distribution for the third quarter of 2013 to the Refining Partnership’s unitholders of $0.30 per common unit or $44.3 million in aggregate. The cash distribution will be paid on November 18, 2013 to unitholders of record at the close of business on November 11, 2013. We will receive $31.4 million in respect of our common units.

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CVR Energy Dividends

On January 24, 2013, our board of directors adopted a quarterly cash dividend policy. Subject to declaration by our board of directors, our quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which we began paying in the second quarter of 2013. Additionally, we declared and paid two special cash dividends during the nine months ended September 30, 2013.

The following is a summary of the quarterly and special dividends paid to stockholders during the nine months ended September 30, 2013:



	February 19, 2013		May 17, 2013		June 10, 2013		August 19, 2013		Total Dividends Paid in 2013
	(in millions, expect per share amounts)
Dividend type	Special		Quarterly		Special		Quarterly
Amount paid to IEP	$	391.6	$	53.4	$	462.8	$	53.4	$	961.2
Amounts paid to public stockholders	86.0		11.7		101.6		11.7		211.0
Total amount paid	$	477.6	$	65.1	$	564.4	$	65.1	$	1,172.2
Per common share	$	5.50	$	0.75	$	6.50	$	0.75	$	13.50
Shares outstanding	86.8		86.8		86.8		86.8

On October 31, 2013, our board of directors declared a dividend for the third quarter of 2013 of $0.75 per share, or $65.1 million in aggregate. The dividend will be paid on November 18, 2013 to stockholders of record at the close of business on November 11, 2013.

Commodity Swaps – Petroleum Segment

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. At September 30, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 20.6 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of future gasoline and distillate production. None of these swap contracts were designated as cash flow hedges, and all changes in fair market value will be reported in earnings in the period in which the value change occurs. For the three months ended September 30, 2013 and 2012, the Refining Partnership recognized a net gain of $72.4 million and a net loss of $161.8 million, respectively. For the nine months ended September 30, 2013 and 2012, the Refining Partnership recognized a net gain of $175.3 million and a net loss of $266.4 million, respectively.

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Results of Operations

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and nine months ended September 30, 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions, except per share amount)
Consolidated Statement of Operations Data:
Net sales	$	1,977.1		$	2,409.6		$	6,549.8		$	6,686.5
Cost of product sold(1)	1,744.4			1,702.5			5,343.5			5,211.9
Direct operating expenses(1)	128.4			109.9			345.2			319.5
Selling, general and administrative expenses(1)	27.7			30.4			85.0			147.7
Depreciation and amortization(1)	36.2			33.1			105.4			97.4
Operating income	40.4			533.7			670.7			910.0
Interest expense and other financing costs	(11.7		)	(18.9		)	(39.6		)	(57.1		)
Interest income	0.3			0.3			0.9			0.5
Gain (loss) on derivatives, net	72.5			(168.9		)	173.0			(277.4		)
Loss on extinguishment of debt	—			—			(26.1		)	—
Other income (expense), net	6.2			(0.1		)	6.5			0.8
Income before income tax expense	107.7			346.1			785.4			576.8
Income tax expense	29.5			127.6			222.8			209.0
Net income(2)	78.2			218.5			562.6			367.8
Less: Net income attributable to noncontrolling interest	34.2			9.6			170.2			29.4
Net income attributable to CVR Energy stockholders	$	44.0		$	208.9		$	392.4		$	338.4

Basic earnings per share	$	0.51		$	2.41		$	4.52		$	3.90
Diluted earnings per share	$	0.51		$	2.41		$	4.52		$	3.86

Weighted-average common shares outstanding:
Basic	86.8			86.8			86.8			86.8
Diluted	86.8			86.8			86.8			87.6



	As of September 30, 2013		As of December 31, 2012
			(audited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	887.1	$	896.0
Working capital	1,395.2		1,135.4
Total assets	3,875.1		3,610.9
Total debt, including current portion	676.4		898.2
Total CVR Energy stockholders’ equity	1,276.2		1,525.1

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	(41.1	)	$	347.9		$	321.3		$	783.8
Investing activities	(62.9		)	(38.8		)	(177.4		)	(143.6		)
Financing activities	(143.4		)	(13.5		)	(152.8		)	(40.3		)
Net cash flow	$	(247.4	)	$	295.6		$	(8.9	)	$	599.9
Other Financial Data
Capital expenditures for property, plant and equipment	$	69.0		$	39.9		$	183.6		$	145.0

(1) Amounts are shown exclusive of depreciation and amortization.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Depreciation and amortization excluded from cost of product sold	$	1.3	$	1.0	$	3.7	$	2.6
Depreciation and amortization excluded from direct operating expenses	34.0		31.6		99.8		93.1
Depreciation and amortization excluded from selling, general and administrative expenses	0.9		0.5		1.9		1.7
Total depreciation and amortization	$	36.2	$	33.1	$	105.4	$	97.4


(2)	The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature. Positive amounts represent expenses which should be added to reported operating income for comparability, while negative amounts should be subtracted for comparability:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Loss on extinguishment of debt(a)	$	—	$	—	$	26.1	$	—
Letter of credit expense included in selling, general and administrative expenses(b)	0.1		0.2		0.4		0.9
Major scheduled turnaround expenses(c)	—		11.3		—		34.8
Share-based compensation expense(d)	3.4		6.5		13.7		28.5
Acquisition and integration expenses—Gary-Williams(e)	—		2.0		—		10.3

(a)

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 repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the nine months ended September 30, 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.

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(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 and nitrogen fertilizer segments.


(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.

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

Consolidated Results of Operations

Net Sales. Consolidated net sales were $1,977.1 million for the three months ended September 30, 2013 compared to $2,409.6 million for the three months ended September 30, 2012. The decrease of $432.5 million was primarily due to lower overall sales volume and lower product prices in the petroleum segment. The lower overall sales volume was driven by the FCCU outage at the Coffeyville refinery during the period. The petroleum segment’s average sales price per gallon for the three months ended September 30, 2013 of $2.89 for gasoline decreased by 4.6% while the average sales price for distillates of $3.07 decreased by approximately 2.5% as compared to the three months ended September 30, 2012. The nitrogen fertilizer segment net sales decreased primarily due to lower ammonia sales volumes and lower UAN sales prices, partially offset by higher UAN sales volumes. The higher UAN sales volumes were primarily attributable to the UAN expansion being operational during the quarter.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $1,744.4 million for the three months ended September 30, 2013, as compared to $1,702.5 million for the three months ended September 30, 2012. The increase of $41.9 million primarily resulted from an increase in cost of product sold at the petroleum segment. The increase at the petroleum segment was primarily due to an increase in the cost of RINs. This increase was partially offset by slightly lower consumed crude costs, due to a reduction of crude throughputs as a result of the FCCU outage at the Coffeyville refinery, offset by higher crude oil prices and lower consumed crude oil discount to WTI. The nitrogen fertilizer segment cost of products sold (exclusive of depreciation and amortization) increased primarily due to increased freight costs and increased ammonia purchases.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $128.4 million for the three months ended September 30, 2013, as compared to $109.9 million for the three months ended September 30, 2012. The increase of $18.5 million was due primarily to increases in repairs and maintenance costs, labor and energy and utility costs in the petroleum segment, partially offset by a decrease in expenses related to the major scheduled turnarounds performed in the prior year. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher costs for repairs and maintenance, utilities and catalyst amortization, partially offset by lower property taxes.

Operating Income. Consolidated operating income was $40.4 million for the three months ended September 30, 2013, as compared to operating income of $533.7 million for the three months ended September 30, 2012, a decrease of $493.3 million. The decrease in operating income was primarily the result of a decrease in the petroleum segment operating income of $484.1 million as a result of lower refining margin and the downtime associated with the FCCU outage. Nitrogen fertilizer segment operating income also decreased $11.0 million primarily as a result of lower net sales.

Interest Expense. Consolidated interest expense for the three months ended September 30, 2013 was $11.7 million as compared to $18.9 million for the three months ended September 30, 2012. This $7.2 million decrease resulted primarily from lower interest expense on the outstanding 2022 Notes for the three months ended September 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the three months ended September 30, 2012.

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Gain (loss) on Derivatives, net. For the three months ended September 30, 2013, we recorded a $72.5 million net gain on derivatives. This compares to a $168.9 million net loss on derivatives for the three months ended September 30, 2012. The change in the 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 2014.

Income Tax Expense. Income tax expense for the three months ended September 30, 2013 was $29.5 million or 27.4% of income before income taxes, as compared to an income tax expense for the three months ended September 30, 2012 of $127.6 million or 36.9% of income before income taxes. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests in CVR Refining’s and CVR Partners’ earnings and the benefits related to the domestic production activities deduction and state income tax credits.

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Consolidated Results of Operations

Net Sales. Consolidated net sales were $6,549.8 million for the nine months ended September 30, 2013 compared to $6,686.5 million for the nine months ended September 30, 2012. The decrease of $136.7 million was primarily due to slightly lower overall sales volume and lower product prices in the petroleum segment. The petroleum segment’s average sales price per gallon for the nine months ended September 30, 2013 of $2.86 for gasoline decreased by 2.4% while the average sales price for distillates of $3.04 decreased approximately 1.0% as compared to the nine months ended September 30, 2012. The nitrogen fertilizer segment net sales increased by $4.7 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 $5,343.5 million for the nine months ended September 30, 2013, as compared to $5,211.9 million for the nine months ended September 30, 2012. The increase of $131.6 million primarily resulted from an increase in the cost of RINs in the petroleum segment. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation and amortization) also increased primarily due to higher freight costs due to increased UAN sales volumes and increased ammonia purchases.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $345.2 million for the nine months ended September 30, 2013, as compared to $319.5 million for the nine months ended September 30, 2012. The increase of $25.7 million was due primarily to increases in repairs and maintenance costs, energy and utility costs, labor and outside services in the petroleum segment, partially offset by a decrease in expenses related to major scheduled turnarounds performed in the prior year. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of increases in utilities, repairs and maintenance costs and catalyst amortization, partially offset by lower property taxes.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $85.0 million for the nine months ended September 30, 2013, as compared to $147.7 million for the nine months ended September 30, 2012. The decrease of $62.7 million was primarily the result of a decrease of $44.2 million related to costs incurred in the prior year associated with the tender offer by certain entities affiliated with IEP and a decrease in share-based compensation of approximately $14.5 million primarily related to the modification of restricted shares to liability-classified restricted stock unit awards during the nine months ended September 30, 2012.

Operating Income. Consolidated operating income was $670.7 million for the nine months ended September 30, 2013, as compared to operating income of $910.0 million for the nine months ended September 30, 2012, a decrease of $239.3 million. Petroleum segment operating income decreased $303.1 million primarily as a result of lower refining margins. Nitrogen fertilizer segment operating income decreased $4.6 million million primarily as a result of higher cost of products sold and direct operating expenses, partially offset by increases in net sales. In addition, decreased corporate selling, general and administrative expenses partially offset the decrease in operating income for the period due to the decreases associated with the tender offer in the prior year and decreases in share-based compensation.

Interest Expense. Consolidated interest expense for the nine months ended September 30, 2013 was $39.6 million as compared to $57.1 million for the nine months ended September 30, 2012. The decrease of $17.5 million resulted primarily from lower interest expense on the outstanding 2022 Notes for the nine months ended September 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the nine months ended September 30, 2012.

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Gain (loss) on Derivatives, net. For the nine months ended September 30, 2013, we recorded a $173.0 million net gain on derivatives. This compares to a $277.4 million net loss on derivatives for the nine months ended September 30, 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 2014.

Loss on Extinguishment of Debt. For the nine months ended September 30, 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. Income tax expense for the nine months ended September 30, 2013 was $222.8 million or 28.4% of income before income taxes, as compared to an income tax expense for the nine months ended September 30, 2012 of $209.0 million or 36.2% of income before income taxes. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests in CVR Refining’s and CVR Partners’ earnings and the benefits related to the domestic production activities deduction and state income tax credits.

Petroleum Business Results of Operations

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 for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions, except as otherwise indicated)
Consolidated Petroleum Segment Summary Financial Results
Net sales	$	1,910.5	$	2,337.3	$	6,322.6	$	6,465.3
Cost of product sold(1)	1,734.7		1,694.0		5,317.0		5,190.8
Direct operating expenses(1)	104.7		77.7		274.5		218.5
Major scheduled turnaround expenses	—		11.1		—		34.6
Depreciation and amortization	28.8		27.5		85.2		80.4
Gross profit(3)	42.3		527.0		645.9		941.0
Plus:
Direct operating expenses and major scheduled turnaround expense(1)	104.7		88.8		274.5		253.1
Depreciation and amortization	28.8		27.5		85.2		80.4
Refining margin(4)	$	175.8	$	643.3	$	1,005.6	$	1,274.5
Operating income	$	23.4	$	507.5	$	588.1	$	891.2
Adjusted Petroleum EBITDA(5)	$	33.9	$	444.2	$	594.5	$	989.7

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Refining margin(4)	$	11.89	$	36.31	$	20.15	$	26.34
Gross profit(3)	$	2.86	$	29.75	$	12.94	$	19.45
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2)	$	7.08	$	5.02	$	5.50	$	5.23
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6)	$	6.92	$	4.81	$	5.29	$	4.75
Barrels sold (barrels per day)(6)	164,431		200,683		190,055		194,638



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
			%			%			%			%
Refining Throughput and Production Data (barrels per day)
Throughput:
Sweet	130,876		78.1	149,768		73.8	147,074		76.9	136,463		73.4
Medium	20,752		12.4	21,188		10.4	17,901		9.4	21,708		11.7
Heavy sour	9,072		5.4	21,607		10.6	17,805		9.3	18,418		9.9
Total crude oil throughput	160,700		95.9	192,563		94.8	182,780		95.6	176,589		95.0
All other feedstocks and blendstocks	6,863		4.1	10,475		5.2	8,444		4.4	9,448		5.0
Total throughput	167,563		100.0	203,038		100.0	191,224		100.0	186,037		100.0
Production:
Gasoline	74,990		45.2	98,016		48.5	89,390		46.8	92,114		49.7
Distillate	69,390		41.8	82,224		40.7	79,230		41.4	75,568		40.8
Other (excluding internally produced fuel)	21,666		13.0	21,928		10.8	22,579		11.8	17,588		9.5
Total refining production (excluding internally produced fuel)	166,046		100.0	202,168		100.0	191,199		100.0	185,270		100.0
Product price (dollars per gallon):
Gasoline	$	2.89		$	3.03		$	2.86		$	2.93
Distillate	$	3.07		$	3.15		$	3.04		$	3.07

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	105.81		$	92.20	$	98.20		$	96.16
Crude Oil Differentials:
WTI less WTS (light/medium sour)	0.30			3.34		2.14			4.10
WTI less WCS (heavy sour)	22.92			15.53		22.27			21.06
NYMEX Crack Spreads:
Gasoline	16.27			31.70		23.92			29.21
Heating Oil	22.13			33.86		27.46			30.54
NYMEX 2-1-1 Crack Spread	19.20			32.78		25.69			29.87
PADD II Group 3 Basis:
Gasoline	(1.57		)	2.22		(2.43		)	(2.58		)
Ultra Low Sulfur Diesel	0.80			5.53		1.66			2.04
PADD II Group 3 Product Crack:
Gasoline	14.70			33.92		21.49			26.63
Ultra Low Sulfur Diesel	22.93			39.38		29.12			32.58
PADD II Group 3 2-1-1	18.81			36.65		25.31			29.60


(1)	Amounts are shown exclusive of depreciation and amortization.


(2)	Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3)

Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from our Condensed Consolidated Statements of Operations. 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) current period settlements on derivative contracts, (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

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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 and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013				2012			2013			2012
				(in millions)
Petroleum Consolidated:
Petroleum operating income	$	23.4			$	507.5		$	588.1		$	891.2
FIFO impacts (favorable), unfavorable(a)	(54.3		)		(50.9		)	(83.3		)	54.3
Share-based compensation, non-cash	2.1				2.3			8.3			8.8
Major scheduled turnaround expenses(b)	—				11.1			—			34.6
Current period settlements on derivative contracts(c)	33.9				(53.2		)	(3.9		)	(80.4		)
Depreciation and amortization	28.8				27.5			85.2			80.4
Other income (expense)	—				(0.1		)	0.1			0.8
Adjusted Petroleum EBITDA	$	33.9			$	444.2		$	594.5		$	989.7

(a)

FIFO is the petroleum business’ basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period.

(b) Represents expense associated with a major scheduled turnaround at the petroleum segment.

(c) Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.


(6)	Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Coffeyville Refinery Financial Results
Net sales	$	992.2	$	1,564.3	$	3,833.9	$	4,143.8
Cost of product sold (exclusive of depreciation and amortization)	893.8		1,135.2		3,206.4		3,327.7
Direct operating expenses (exclusive of depreciation and amortization)	68.4		47.3		170.7		134.7
Major scheduled turnaround expenses	—		0.2		—		21.2
Depreciation and amortization	17.7		17.4		52.9		52.1
Gross profit	12.3		364.2		403.9		608.1
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	68.4		47.5		170.7		155.9
Depreciation and amortization	17.7		17.4		52.9		52.1
Refining margin	$	98.4	$	429.1	$	627.5	$	816.1

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(dollars per barrel)
Coffeyville Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	13.48	$	37.42	$	21.56	$	26.71
Gross profit	$	1.69	$	31.76	$	13.88	$	19.90
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	9.37	$	4.14	$	5.86	$	5.10
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	9.12	$	3.90	$	5.51	$	4.58
Barrels sold (barrels per day)	81,532		132,372		113,518		124,172



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
		%		%		%		%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	69,785	84.0	100,427	76.0	88,337	78.4	90,871	77.0
Medium	514	0.6	2,609	2.0	454	0.4	2,216	1.9
Heavy sour	9,072	10.9	21,607	16.4	17,805	15.8	18,418	15.6
Total crude oil throughput	79,371	95.5	124,643	94.4	106,596	94.6	111,505	94.5
All other feedstocks and blendstocks	3,711	4.5	7,465	5.6	6,067	5.4	6,448	5.5
Total throughput	83,082	100.0	132,108	100.0	112,663	100.0	117,953	100.0
Production:
Gasoline	35,493	42.4	63,991	47.8	52,507	45.8	58,889	49.2
Distillate	35,206	42.0	56,230	42.0	48,018	41.9	50,766	42.4
Other (excluding internally produced fuel)	13,050	15.6	13,756	10.2	14,003	12.3	10,014	8.4
Total refining production (excluding internally produced fuel)	83,749	100.0	133,977	100.0	114,528	100.0	119,669	100.0



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Wynnewood Refinery Financial Results
Net sales	$	917.2	$	772.8	$	2,485.4	$	2,321.0
Cost of product sold (exclusive of depreciation and amortization)	841.1		559.5		2,110.2		1,864.9
Direct operating expenses (exclusive of depreciation and amortization)	36.2		30.1		103.8		83.6
Major scheduled turnaround expenses	—		11.0		—		13.4
Depreciation and amortization	9.9		9.0		28.7		25.7
Gross Profit	30.0		163.2		242.7		333.4
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	36.2		41.1		103.8		97.0
Depreciation and amortization	9.9		9.0		28.7		25.7
Refining margin	$	76.1	$	213.3	$	375.2	$	456.1

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(dollars per barrel)
Wynnewood Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	10.17	$	34.13	$	18.04	$	25.58
Gross profit	$	4.00	$	26.12	$	11.66	$	18.70
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	4.85	$	6.58	$	4.99	$	5.44
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	4.75	$	6.54	$	4.97	$	5.02
Barrels sold (barrels per day)	82,899		68,311		76,537		70,466



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
		%		%		%		%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	61,091	72.3	49,341	69.6	58,737	74.8	45,592	67.0
Medium	20,238	24.0	18,579	26.2	17,447	22.2	19,492	28.6
Heavy sour	—	—	—	—	—	—	—	—
Total crude oil throughput	81,329	96.3	67,920	95.8	76,184	97.0	65,084	95.6
All other feedstocks and blendstocks	3,152	3.7	3,010	4.2	2,377	3.0	3,000	4.4
Total throughput	84,481	100.0	70,930	100.0	78,561	100.0	68,084	100.0
Production:
Gasoline	39,497	48.0	34,025	49.9	36,883	48.1	33,225	50.7
Distillate	34,184	41.5	25,994	38.1	31,212	40.7	24,802	37.8
Other (excluding internally produced fuel)	8,616	10.5	8,172	12.0	8,576	11.2	7,574	11.5
Total refining production (excluding internally produced fuel)	82,297	100.0	68,191	100.0	76,671	100.0	65,601	100.0

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012 (Petroleum Business)

Net Sales. Petroleum net sales were $1,910.5 million for the three months ended September 30, 2013 compared to $2,337.3 million for the three months ended September 30, 2012. The decrease of $426.8 million was the result of lower overall sales volume due to the FCCU outage at the Coffeyville refinery and lower product prices. Our average sales price per gallon for the three months ended September 30, 2013 for gasoline of $2.89 decreased by approximately 4.6% as compared to the three months ended September 30, 2012. Our average sales price per gallon for the three months ended September 30, 2013 for distillates of $3.07 decreased by approximately 2.5% as compared to the same period in 2012.



	Three Months Ended September 30, 2013					Three Months Ended September 30, 2012					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	7.7	$	121.55	$	935.3	9.6	$	127.27	$	1,220.5	(1.9	)	$	(285.2	)	$	(44.1	)	$	(241.1	)
Distillate	6.5	$	128.98	$	840.5	7.6	$	132.18	$	1,001.6	(1.1	)	$	(161.1	)	$	(20.9	)	$	(140.2	)


(1)	Barrels in millions


(2)	Sales dollars in millions

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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, RINs, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $1,734.7 million for the three months ended September 30, 2013 compared to $1,694.0 million for the three months ended September 30, 2012. Cost of products sold increased by $40.7 million despite the decrease in sales volume of approximately 16%. The cost increase was primarily due to an increase in the cost of RINS. Consumed crude cost for the quarter ended September 30, 2013 as compared to the same period last year was slightly lower. The consumed crude cost reduction was due to a decline in crude oil throughputs by 16.5% as a result of the FCCU outage at the Coffeyville refinery this quarter, largely offset by a rise in market prices of crude oil and a narrowing of the petroleum segment's consumed crude oil discount to WTI for this quarter as compared to the same quarter last year. The consumed crude oil discount to WTI for the third quarter of 2013 was $1.25 per barrel as compared to $4.38 in the third quarter of 2012.

Refining margin per barrel of crude oil throughput decreased from $36.31 for the three months ended September 30, 2012 to $11.89 for the three months ended September 30, 2013. Refining margin adjusted for FIFO impact was $8.21 per crude oil throughput barrel for the three months ended September 30, 2013, as compared to $33.44 per crude oil throughput barrel for the three months ended September 30, 2012. Gross profit per barrel decreased to $2.86 for the three months ended September 30, 2013 as compared to gross profit per barrel of $29.75 in the equivalent period in 2012. The decrease in refining margin and gross margin per barrel was a function of the decrease in sales and increase in crude oil prices.

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 $104.7 million for the three months ended September 30, 2013 compared to direct operating expenses and major scheduled turnaround expenses of $88.8 million for the three months ended September 30, 2012. The increase of $15.9 million was primarily the result of the increase in expenses associated with repairs and maintenance costs, largely due to the FCCU outage at the Coffeyville refinery ($22.5 million), labor ($4.8 million) and energy and utility costs ($1.4 million). These increases were partially offset by a decrease in expenses associated with a major scheduled turnaround performed in the prior year ($11.1 million). Direct operating expenses per barrel of crude oil throughput for the three months ended September 30, 2013 increased to $7.08 per barrel as compared to $5.02 per barrel for the three months ended September 30, 2012. The increase in the direct operating expenses per barrel of crude oil throughput is a function of the higher overall expenses and lower volume of crude oil throughput in 2013.

Operating Income. Petroleum operating income was $23.4 million for the three months ended September 30, 2013 as compared to operating income of $507.5 million for the three months ended September 30, 2012. This decrease of $484.1 million was the result of a decrease in the refining margin ($467.5 million), an increase in direct operating expenses ($15.9 million) and an increase in depreciation and amortization ($1.3 million), partially offset by a decrease in selling, general and administrative expenses ($0.6 million).

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012 (Petroleum Business)

Net Sales. Petroleum net sales were $6,322.6 million for the nine months ended September 30, 2013 compared to $6,465.3 million for the nine months ended September 30, 2012. The decrease of $142.7 million was the result of slightly lower overall sales volumes and lower product prices. Our average sales price per gallon for the nine months ended September 30, 2013 for gasoline of $2.86 decreased by approximately 2.4% as compared to the nine months ended September 30, 2012. Our average sales price per gallon for the nine months ended September 30, 2013 for distillates of $3.04 decreased by approximately 1.0% as compared to the same period in 2012.



	Nine Months Ended September 30, 2013					Nine Months Ended September 30, 2012					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	26.5	$	120.11	$	3,182.8	27.4	$	123.18	$	3,380.3	(0.9	)	$	(197.5	)	$	(81.4	)	$	(116.1	)
Distillate	21.8	$	127.83	$	2,790.4	21.4	$	128.98	$	2,760.1	0.4		$	30.3		$	(25.2	)	$	55.5


(1)	Barrels in millions


(2)	Sales dollars in millions

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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, RINs, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $5,317.0 million for the nine months ended September 30, 2013 compared to $5,190.8 million for the nine months ended September 30, 2012. The increase of $126.2 million was primarily the result of an increase in the cost of RINs and higher crude oil prices, partially offset by slightly lower sales volumes. Our average cost per barrel of crude oil consumed for the nine months ended September 30, 2013 was $94.52 compared to $92.76 for the comparable period of 2012, an increase of approximately 1.9%. Sales volume of refined fuels decreased by approximately 0.7%. 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 nine months ended September 30, 2013, we had a favorable FIFO inventory impact of $83.3 million compared to an unfavorable FIFO inventory impact of $54.3 million for the comparable period of 2012.

Refining margin per barrel of crude oil throughput decreased from $26.34 for the nine months ended September 30, 2012 to $20.15 for the nine months ended September 30, 2013. Refining margin adjusted for FIFO impact was $18.48 per crude oil throughput barrel for the nine months ended September 30, 2013, as compared to $27.46 per crude oil throughput barrel for the nine months ended September 30, 2012. Gross profit per barrel decreased to $12.94 for the nine months ended September 30, 2013 as compared to gross profit per barrel of $19.45 in the equivalent period in 2012. The decrease in refining margin and gross margin per barrel is primarily due to a decrease in sales prices of gasoline and distillates, an increase in RINs costs and an increase in the per barrel cost of consumed crude oil. Consumed crude oil costs increased due to a 2.1% increase in WTI for the nine months ended September 30, 2013 over the nine months ended September 30, 2012.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $274.5 million for the nine months ended September 30, 2013 compared to direct operating expenses and major scheduled turnaround expenses of $253.1 million for the nine months ended September 30, 2012. The increase of $21.4 million was primarily the result of the increase in expenses associated with repairs and maintenance ($35.7 million), labor ($9.3 million), energy and utility costs ($9.0 million) and outside services ($3.7 million). These increases were partially offset by a decrease in major scheduled turnaround performed in the prior year ($34.6 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 nine months ended September 30, 2013 increased to $5.50 per barrel as compared to $5.23 per barrel for the nine months ended September 30, 2012. The increase in the direct operating expenses per barrel of crude oil throughput is a function of the higher overall expenses.

Operating Income. Petroleum operating income was $588.1 million for the nine months ended September 30, 2013 as compared to operating income of $891.2 million for the nine months ended September 30, 2012. This decrease of $303.1 million was the result of a decrease in the refining margin ($268.9 million), an increase in direct operating expense ($21.4 million), an increase in selling, general and administrative expense ($8.0 million) and an increase in depreciation and amortization ($4.8 million).

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Nitrogen Fertilizer Business Results of Operations

The tables below provide an overview of the nitrogen fertilizer business’ results of operations, relevant market indicators and key operating statistics for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Nitrogen Fertilizer Business Financial Results
Net sales	$	69.2	$	75.0	$	239.4	$	234.7
Cost of product sold(1)	13.0		11.3		39.2		34.6
Direct operating expenses(1)	23.7		21.1		70.7		66.4
Selling, general and administrative(1)	4.6		5.1		15.8		18.1
Depreciation and amortization	6.6		5.2		18.5		15.8
Operating income	$	21.3	$	32.3	$	95.2	$	99.8
Adjusted Nitrogen Fertilizer EBITDA(2)	$	28.2	$	39.0	$	116.1	$	121.1



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(3)	100.4			104.2			303.0			302.3
Ammonia (net available for sale)(3)(4)	3.4			29.4			36.3			89.3
UAN	239.3			181.9			660.6			516.5
Pet coke consumed (thousand tons)	116.0			126.9			360.2			377.7
Pet coke (cost per ton)	$	30		$	30		$	30		$	34
Sales (thousand tons)(5):
Ammonia	3.3			30.2			37.9			89.5
UAN	226.7			175.1			638.1			510.5
Product pricing (plant gate) (dollars per ton)(5):
Ammonia	$	505		$	578		$	654		$	586
UAN	$	259		$	290		$	295		$	311
On-stream factor(6):
Gasification	91.2		%	99.1		%	94.1		%	97.2		%
Ammonia	90.1		%	98.4		%	92.6		%	96.0		%
UAN	89.5		%	96.9		%	89.6		%	92.4		%
Reconciliation of net sales (dollars in millions):
Sales net plant gate	$	60.4		$	68.2		$	212.9		$	211.1
Freight in revenue	7.8			6.5			21.6			17.6
Hydrogen revenue	0.8			0.3			4.7			6.0
Other revenue	0.2			—			0.2			—
Total net sales	$	69.2		$	75.0		$	239.4		$	234.7

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Market Indicators
Natural gas NYMEX (dollars per MMBtu)	$	3.56	$	2.89	$	3.69	$	2.58
Ammonia — Southern Plains (dollars per ton)	498		677		611		616
UAN — Mid Cornbelt (dollars per ton)	302		356		352		372


(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 and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Nitrogen Fertilizer:
Nitrogen fertilizer operating income	$	21.3	$	32.3	$	95.2	$	99.8
Share-based compensation, non-cash	0.3		1.2		2.3		5.2
Depreciation and amortization	6.6		5.2		18.5		15.8
Major scheduled turnaround expense	—		0.2		—		0.2
Other income, net	—		0.1		0.1		0.1
Adjusted Nitrogen Fertilizer EBITDA	$	28.2	$	39.0	$	116.1	$	121.1


(3)	Gross tons produced for ammonia represent total ammonia, including ammonia produced that was upgraded into UAN. As a result of the UAN expansion project completed in February 2013, the Nitrogen Fertilizer Partnership now upgrades substantially all of the ammonia they produce into UAN. The net tons available for sale represent ammonia available for sale that was not upgraded into UAN.


(4)	In addition to produced ammonia, during the three and nine months ended September 30, 2013, the Nitrogen Fertilizer Partnership acquired approximately 1,000 tons and 5,000 tons of ammonia, which was upgraded to UAN.


(5)	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.

(6)

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 planned downtime associated with the replacement of the damaged catalyst, the on-stream factors for the three months ended September 30, 2013 would have been 98.7% for gasifier, 98.2% for ammonia and 97.8% for UAN.

Excluding the impacts of the UAN expansion coming on-line, the planned downtime associated with replacement of the damaged catalyst, the unplanned Linde air separation unit outages and the unplanned downtime associated with weather

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issues, the on-stream factors for the nine months ended September 30, 2013 would have been 99.3% for gasifier, 98.7% for ammonia and 97.7% for UAN.

Three Months Ended September 30, 2013 compared to the Three Months Ended September 30, 2012 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $69.2 million for the three months ended September 30, 2013 compared to $75.0 million for the three months ended September 30, 2012. The decrease of $5.8 million was the result of lower ammonia sales volumes ($14.4 million), lower UAN sales prices ($5.2 million) and lower ammonia sales prices ($2.0 million), partially offset by higher UAN sales volumes ($15.1 million) combined with higher hydrogen sales volumes ($0.5 million). For the three months ended September 30, 2013, ammonia and UAN made up $1.7 million and $66.5 million of nitrogen fertilizer net sales, respectively. This compared to ammonia and UAN net sales of $18.1 million and $56.6 million, respectively, for the three months ended September 30, 2012. The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the three months ended September 30, 2013 and September 30, 2012:



	Three Months Ended September 30, 2013					Three Months Ended September 30, 2012					Total Variance					Price Variance			Volume 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	3,251	$	533	$	1.7	30,197	$	601	$	18.1	(26,946	)	$	(16.4	)	$	(2.0	)	$	(14.4	)
UAN	226,714	$	293	$	66.5	175,059	$	323	$	56.6	51,655		$	9.9		$	(5.2	)	$	15.1
Hydrogen	99,260	$	8	$	0.8	30,809	$	9	$	0.3	68,451		$	0.5		$	—		$	0.5

(1) Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF.

(2) Includes freight charges

(3) Sales dollars in millions

The increase in UAN sales volume for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 was primarily attributable to the UAN expansion being in operation 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 were 91.2%, 90.1% and 89.5%, respectively, for the three months ended September 30, 2013. Excluding the impact of the downtime associated with the planned replacement of the damaged catalyst in July, the on-stream rates for the three months ended September 30, 2013 would have been 98.7% for gasifier, 98.2% for ammonia and 97.8% for UAN.

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 September 30, 2013 compared to the three months ended September 30, 2012 decreased 12.6% for ammonia and decreased 10.7% for UAN.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer 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 September 30, 2013 was $13.0 million, compared to $11.3 million for the three months ended September 30, 2012. The $1.7 million increase resulted from $2.4 million in higher costs from transactions with third parties, partially offset by lower costs from transactions with affiliates of $0.7 million. The higher third-party costs incurred during the three months ended September 30, 2013 were primarily the result of ammonia purchases and increased freight costs.

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 September 30, 2013 were $23.7 million as compared to $21.1 million for the three months ended September 30, 2012. The $2.6 million increase resulted primarily from higher utilities ($1.6 million), repairs and maintenance costs ($1.1 million), catalyst amortization ($1.0 million), chemicals ($0.5 million) and outside services ($0.5 million), partially offset by lower property taxes ($3.3 million). Additionally, direct operating expenses in the prior year period were reduced

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by insurance proceeds received for the reactor rupture ($1.0 million). The increased utility costs were largely due to the UAN expansion, which came on-line in February 2013. The increases to repairs and maintenance and the catalyst amortization are largely a result of the planned replacement of the damaged catalyst.

Operating Income. Nitrogen fertilizer operating income was $21.3 million for the three months ended September 30, 2013, as compared to operating income of $32.3 million for the three months ended September 30, 2012. The decrease of $11.0 million for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 was the result of the decrease in sales ($5.8 million) and increases in cost of products sold ($1.7 million), direct operating expenses ($2.6 million) and depreciation and amortization ($1.4 million), partially offset by a decrease in selling, general and administrative expenses ($0.5 million).

Nine Months Ended September 30, 2013 compared to the Nine Months Ended September 30, 2012 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $239.4 million for the nine months ended September 30, 2013 compared to $234.7 million for the nine months ended September 30, 2012. The increase of $4.7 million was the result of higher sales volumes for UAN ($41.8 million) and higher prices for ammonia ($6.0 million), offset by lower sales volumes for ammonia ($34.7 million), lower prices for UAN ($7.3 million) and reduced hydrogen sales to the Refining Partnership’s refinery ($1.2 million). For the nine months ended September 30, 2013, ammonia and UAN made up $25.5 million and $209.0 million of our net sales, respectively. This compared to ammonia and UAN net sales of $54.2 million and $174.5 million, respectively, for the nine months ended September 30, 2012. The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the nine months ended September 30, 2013 and September 30, 2012:



	Nine Months Ended September 30, 2013					Nine Months Ended September 30, 2012					Total Variance					Price Variance			Volume 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	37,891	$	672	$	25.5	89,477	$	605	$	54.2	(51,586	)	$	(28.7	)	$	6.0		$	(34.7	)
UAN	638,142	$	328	$	209.0	510,520	$	342	$	174.5	127,622		$	34.5		$	(7.3	)	$	41.8
Hydrogen	477,075	$	10	$	4.7	593,466	$	10	$	6.0	(116,391	)	$	(1.3	)	$	(0.1	)	$	(1.2	)

(1) Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF.

(2) Includes freight charges

(3) Sales dollars in millions

The increase in UAN sales volume for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily attributable to the UAN expansion coming on-line in February of 2013. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units were 94.1%, 92.6% and 89.6%, respectively, for the nine months ended September 30, 2013. Excluding the impacts of the UAN expansion coming on-line, the planned downtime associated with the replacement of the damaged catalyst, the unplanned Linde air separation unit outages and the unscheduled downtime associated with weather issues, the on-stream factors for the nine months ended September 30, 2013 would have been 99.3% for gasifier, 98.7% for ammonia and 97.7% for UAN.

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 nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 increased 11.6% for ammonia and decreased 5.1% for UAN.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold is primarily comprised of pet coke expense, freight expense and distribution expense. Cost of product sold for the nine months ended September 30, 2013 was $39.2 million compared to $34.6 million for the nine months ended September 30, 2012. The increase of $4.6 million is primarily the result of higher third-party costs ($4.9 million) associated with increased freight costs due to the increase in UAN sales volumes and purchased ammonia costs.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance,

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energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) for the nine months ended September 30, 2013 were $70.7 million as compared to $66.4 million for the nine months ended September 30, 2012. The $4.3 million increase was largely the result of increased utilities ($3.6 million), repairs and maintenance costs ($2.3 million), catalyst amortization ($1.7 million), insurance ($1.2 million), chemicals ($1.0 million), labor ($0.7 million) and outside services ($0.6 million), partially offset by lower property taxes ($8.7 million). Additionally, direct operating expenses in the prior year period were reduced by insurance proceeds received for the reactor rupture ($1.0 million). The increased utility costs were largely due to the UAN expansion, which came on-line in February 2013. The increases to repairs and maintenance and the catalyst amortization are partially the result of the planned replacement of the damaged catalyst.

Operating Income. Nitrogen fertilizer operating income was $95.2 million for the nine months ended September 30, 2013 as compared to operating income of $99.8 million for the nine months ended September 30, 2012. This decrease of $4.6 million was due to increases in cost of product sold ($4.6 million), direct operating costs ($4.3 million) and depreciation and amortization ($2.7 million), partially offset by the increase in net sales ($4.7 million) and decrease in selling, general and administrative expenses ($2.3 million).

Liquidity and Capital Resources

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 Partnership's 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.

Cash Balance and Other Liquidity

As of September 30, 2013, we had consolidated cash and cash equivalents of $887.1 million. Of that amount, $549.4 million was cash and cash equivalents of CVR Energy, $250.5 million was cash and cash equivalents of the Refining Partnership and $87.2 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of October 29, 2013, we had consolidated cash and cash equivalents of approximately $869.9 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 September 30, 2013, the Refining Partnership had $372.9 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 September 30, 2013, the Nitrogen Fertilizer Partnership had $25.0 million available under the credit facility.

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The Refining Partnership and the Nitrogen Fertilizer Partnership have distribution policies pursuant to which they will generally distribute all of their available cash each quarter, within 60 days after the end of each quarter. The Refining Partnership’s distributions began with the quarter ending March 31, 2013 and were 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. At September 30, 2013, we currently hold approximately 71% and 53% 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 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.

Borrowing Activities

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 redeem 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 September 30, 2013, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.

The 2022 Notes were issued by Refining LLC and Coffeyville Finance and are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. 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 Energy, CVR Partners and CRNF are not guarantors. 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, which occurred on January 23, 2013. Accordingly, the 2022 Notes were no longer secured as of and after January 23, 2013.

On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership incurred approximately $0.1 million and $0.4 million of debt registration costs related to the registration and exchange offer during the three and nine months ended September 30, 2013, respectively, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method.

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

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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, plus in each case, 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 contractually subordinated 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. The Refining Partnership was in compliance with the covenants as of September 30, 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 swingline 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).

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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 September 30, 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 2010 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 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 September 30, 2013, no amounts were drawn under the Nitrogen Fertilizer Partnership’s $25.0 million revolving credit facility.

Nitrogen Fertilizer Partnership Interest Rate Swap

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 qualify for hedge accounting treatment. The impact recorded for the three months ended September 30, 2013 and 2012 is $0.3 million and $0.2 million, respectively, in interest expense. The impact recorded for the nine months ended September 30, 2013 and 2012 is $0.8 million and $0.7 million, respectively, in interest expense. For the three months ended September 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized a decrease in fair value on the Interest Rate Swap agreements of $0.3 million and $0.4 million, respectively, which is unrealized in accumulated other comprehensive income. For the nine months ended September 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized a decrease in fair value on the Interest Rate Swap agreements of $0.1 million and $1.3 million, respectively, which is unrealized in accumulated other comprehensive income.

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Capital Spending

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 nine months ended September 30, 2013 by operating segment and major category:



	Nine Months Ended September 30, 2013
	(in millions)
Petroleum Business (the Refining Partnership):
Coffeyville refinery:
Maintenance	$	37.4
Growth	2.2
Coffeyville refinery total capital	39.6
Wynnewood refinery:
Maintenance	74.0
Growth	17.1
Wynnewood refinery total capital	91.1
Other Petroleum:
Maintenance	7.8
Growth	2.3
Other petroleum total capital	10.1
Petroleum business total capital	140.8
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
Maintenance	2.0
Growth	33.8
Nitrogen fertilizer business total capital	35.8
Corporate	7.0
Total capital spending	$	183.6

Including amounts already spent during the nine months ended September 30, 2013, the petroleum business expects to spend, in total, approximately $190.0 million to $215.0 million (excluding capitalized interest) on capital expenditures for the year ending December 31, 2013. Of this amount $55.0 million to $65.0 million is expected to be spent for the Coffeyville refinery which includes approximately $50.0 million to $60.0 million of maintenance capital. Approximately $120.0 million to $135.0 million is expected to be spent on capital for the Wynnewood refinery which includes approximately $90.0 million to $100.0 million of maintenance capital. We also expect to spend $15.0 million on other petroleum capital projects and approximately $8.0 million to $10.0 million associated with corporate related projects.

Including amounts already spent during the nine months ended September 30, 2013, the nitrogen fertilizer business expects to spend, in total, $40.0 million to $48.0 million on capital expenditures for the year ending December 31, 2013 (excluding capitalized interest). Of this amount, $5.0 million will be spent on maintenance projects and $35.0 million to $43.0 million will be spent on growth projects including approximately $25.0 million spent related to 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 expanded facility was running 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. Total capital expenditures associated with the UAN expansion were approximately $130.0 million, excluding capitalized interest.

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Cash Flows

The following table sets forth our cash flows for the periods indicated below:



	Nine Months Ended September 30,
	2013			2012
	(unaudited)
	(in millions)
Net cash provided by (used in):
Operating activities	$	321.3		$	783.8
Investing activities	(177.4		)	(143.6		)
Financing activities	(152.8		)	(40.3		)
Net (decrease) increase in cash and cash equivalents	$	(8.9	)	$	599.9

Cash Flows Provided by Operating Activities

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 nine months ended September 30, 2013 were $321.3 million. The positive cash flow from operating activities generated over this period was primarily driven by $562.6 million of net income before noncontrolling interest and $70.8 million of favorable impacts to other working capital, partially offset by unfavorable impacts to trade working capital of $204.4 million. Trade working capital for the nine months ended September 30, 2013 resulted in a cash outflow of $204.4 million, which was attributable to increases in accounts receivable ($30.9 million) and inventory ($152.2 million) and a decrease in accounts payable ($21.3 million). Other working capital activities resulted in net cash inflow of $70.8 million, which was primarily related to increases in due to parent ($42.9 million) and other current liabilities ($14.8 million).

Net cash flows provided by operating activities for the nine months ended September 30, 2012 were $783.8 million. The positive net cash flow from operating activities was primarily driven by net income before noncontrolling interest of $367.8 million, which was primarily the result of higher operating margins. This positive operating cash flow from net income was coupled with a favorable change in other working capital, offset by unfavorable changes in trade working capital. Trade working capital for the nine months ended September 30, 2012 resulted in a cash outflow of $28.9 million million as a result of a decrease in accounts payable ($42.8 million) coupled with an increase in accounts receivable ($98.0 million), offset by a decrease in inventories ($111.9 million).

Cash Flows Used in Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2013 was $177.4 million compared to $143.6 million for the nine months ended September 30, 2012. The increase in cash used in investing activities was primarily the result of an increase in capital expenditures of $38.6 million. The petroleum business’ capital expenditures increased $58.0 million for the nine months ended September 30, 2013 compared to the same period in 2012, largely due to projects at the Wynnewood refinery. This increase was offset by a decrease in nitrogen fertilizer capital expenditures of $21.6 million primarily related to decreased capital expenditures for the UAN expansion, which was completed in February 2013.

Cash Flows Used In Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2013 was approximately $152.8 million as compared to $40.3 million for the nine months ended September 30, 2012. The net cash used in financing activities for the nine months ended September 30, 2013 was primarily attributable to dividend payments to common stockholders of $1,172.2 million, distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $139.1 million and payments to extinguish the Second Lien Notes of $243.4 million, largely offset by proceeds from CVR Refining’s initial public offering of $655.7 million, proceeds from CVR Refining’s Underwritten Offering of $393.6 million, proceeds from CVR Energy’s sale of CVR Refining’s units to AEPC of $61.5 million and proceeds from the Secondary Offering of CVR Partner’s common units of $292.6 million.

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Net cash used in financing activities for the nine months ended September 30, 2012 was $40.3 million. During the nine months ended September 30, 2012, we paid a cash distribution to noncontrolling interest holders of the Nitrogen Fertilizer Partnership totaling $37.8 million. Additionally, financing costs of approximately $2.0 million were paid during the period associated with increasing the borrowing capacity of the ABL credit facility and the issuance of additional notes in December 2011.

For the three and nine months ended September 30, 2013, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility. As of September 30, 2013, there were no short-term borrowings outstanding under the Amended and Restated ABL credit facility.

Capital and Commercial Commitments

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 September 30, 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 September 30, 2013 and thereafter. As of September 30, 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)	38.8		2.4		9.3		7.9		6.8		4.2		8.2
Capital lease obligations(3)	51.4		0.3		1.3		1.4		1.6		1.8		45.0
Unconditional purchase obligations(4)	1,440.7		85.3		113.1		101.4		94.2		93.0		953.7
Environmental liabilities(5)	2.1		0.2		0.4		0.2		0.1		0.1		1.1
Interest payments(6)	365.0		10.6		42.2		42.1		38.6		37.1		194.4
Total	$	2,523.0	$	98.8	$	166.3	$	153.0	$	266.3	$	136.2	$	1,702.4
Other Commercial Commitments
Standby letters of credit(7)	$	27.1	$	—	$	—	$	—	$	—	$	—	$	—


(1)	Consists of the 2022 Notes and the Nitrogen Fertilizer Partnership’s term loan facility outstanding on September 30, 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, (e) commitments related to our biofuels blending obligation and (f) approximately $965.5 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. The Refining Partnership began receiving crude oil under the agreements in the first quarter of 2011.

(5)

Environmental liabilities represents 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. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Commitments and Contingencies — Environmental, Health & Safety Matters.”


(6)	Interest payments are based on stated interest rates for our long-term debt outstanding on September 30, 2013 and interest payments for the capital lease obligations.

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(7)	Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil and a $0.6 million letter of credit issued to guarantee a portion of our insurance policy.

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 or seek 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. In addition, CVR Energy, the Refining Partnership and/or the Nitrogen Fertilizer Partnership may from time to time seek to issue debt or equity securities in the public or private capital markets, but there can be no assurance they will be able to do so at prices they deem reasonable or at all.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2013, as defined within the rules and regulations of the SEC.

Recent Accounting Pronouncements

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.

In July 2013, the FASB issued ASU No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” (“ASU 2013-11”). ASU 2013-11 requires the netting of unrecognized tax benefits against a deferred tax asset for a loss or other carryforward that would apply in settlement of the uncertain tax positions. The standard is effective for interim and annual periods beginning after December 15, 2013 and is to be applied prospectively with optional retrospective adoption permitted. The adoption of this standard is effective on January 1, 2014. We are currently evaluating the standard but do not expect that it will materially impact our condensed consolidated financial statements or footnote disclosures.

Critical Accounting Policies

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. Information about market risks for the nine months ended September 30, 2013 does not differ materially

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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.

Commodity Price Risk

At September 30, 2013, the Refining Partnership had open commodity hedging instruments consisting of 20.6 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 September 30, 2013 was a net unrealized gain of $110.1 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 $20.6 million.

Interest Rate Risk

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 September 30, 2013, the effective rate was approximately 4.57%. 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 3.50%, 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 Nitrogen Fertilizer Partnership’s net income by the same amount.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 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

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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.

Changes in Internal Control Over Financial Reporting

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 September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

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.

Item 1A. Risk Factors

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 and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. However, we have updated the following risk factor which was included in our Form 10-Q for the quarter ended June 30, 2013.

We may be subject to the pension liabilities of our affiliates.

As a result of the more than 80% ownership interest in us by Mr. Icahn's affiliates, we are subject to the pension liabilities of all entities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. One such entity, ACF Industries LLC, is the sponsor of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of September 30, 2013. If the ACF plans were voluntarily terminated, they would be underfunded by approximately $116.9 million as of September 30, 2013. As a result of Mr. Icahn's affiliates obtaining approximately 80.7% of the outstanding common stock of Federal-Mogul Corporation (“Federal-Mogul”) during the three months ended September 30, 2013, the Company is also subject to the pension liabilities of Federal-Mogul. If the plans of Federal-Mogul and ACF were voluntarily terminated, as of September 30, 2013, they would collectively be underfunded by approximately $702.9 million. These results are based on the most recent information provided to us by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. As members of the controlled group, we would be liable for any failure of ACF and Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes us may have pension plan obligations that are, or may become, underfunded, and we would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain “reportable events,” such as if we cease to be a member of the controlled group, or if we make certain extraordinary dividends or stock redemptions. The obligation to report could cause us to seek to delay or reconsider the occurrence of such reportable events.

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Item 6. Exhibits



Number		Exhibit Title
	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.
	101*	The following financial information for CVR Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 1, 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.
	*	Filed herewith.

PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports that we file with or furnish to the SEC. The agreements are 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CVR Energy, Inc.



November 1, 2013	By:	/s/ JOHN J. LIPINSKI
		Chief Executive Officer
		(Principal Executive Officer)

November 1, 2013	By:	/s/ SUSAN M. BALL
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

CVI Q3 Exhibit 31.1

Exhibit 31.1

Certification by Chief Executive Officer Pursuant to

Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, John J. Lipinski, certify that:

1. I have reviewed this Report on Form 10-Q of CVR Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



By:	/s/ JOHN J. LIPINSKI
	John J. Lipinski
	Chief Executive Officer

Date: November 1, 2013

CVI Q3 Exhibit 31.2

Exhibit 31.2

Certification of Chief Financial Officer Pursuant to

Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Susan M. Ball, certify that:

1. I have reviewed this Report on Form 10-Q of CVR Energy, Inc.;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



By:	/s/ SUSAN M. BALL
	Susan M. Ball
	Chief Financial Officer

Date: November 1, 2013

CVI Q3 Exhibit 32.1

Exhibit 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

In connection with the filing of the Quarterly Report of CVR Energy, Inc., a Delaware corporation (the “Company”) on Form 10-Q for the fiscal quarter ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John J. Lipinski, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.



By:	/s/ JOHN J. LIPINSKI
	John J. Lipinski
	Chief Executive Officer

Dated: November 1, 2013

CVI Q3 Exhibit 32.2

Exhibit 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

In connection with the filing of the Quarterly Report of CVR Energy, Inc., a Delaware corporation (the “Company”) on Form 10-Q for the fiscal quarter ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Susan M. Ball, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



By:	/s/ SUSAN M. BALL
	Susan M. Ball
	Chief Financial Officer

Dated: November 1, 2013