Edgar Filing: CVR ENERGY INC

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if smaller reporting company.)

CVI Q3 2014 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended September 30, 2014

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 28, 2014.

CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2014



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

	Condensed Consolidated Balance Sheets - September 30, 2014 (unaudited) and December 31, 2013	6

	Condensed Consolidated Statements of Operations - Three and Nine Months Ended September 30, 2014 and 2013 (unaudited)	7

	Condensed Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2014 and 2013 (unaudited)	8

	Condensed Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2014 (unaudited)	9

	Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2014 and 2013 (unaudited)	10

	Notes to the Condensed Consolidated Financial Statements - September 30, 2014 (unaudited)	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	72

Item 4.	Controls and Procedures	73

Part II. Other Information

Item 1.	Legal Proceedings	74

Item 1A.	Risk Factors	74

Item 6.	Exhibits	74

Signatures		75

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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, 2014 (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 day.

bpcd — 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.

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

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

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

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

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

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

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

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.

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

product pricing at gate — Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons.

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.

Second Underwritten Offering — The second underwritten offering of 7,475,000 common units of the Refining Partnership, which closed on June 30, 2014 (which includes the underwriters’ subsequently-exercised option to purchase additional common units).

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 to three years for the nitrogen fertilizer plant.

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

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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.

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, 2014			December 31, 2013
	(unaudited)
	(in millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	793.1		$	842.1
Accounts receivable, net of allowance for doubtful accounts of $0.5 and $0.9, respectively	230.5			241.9
Inventories	516.8			526.6
Prepaid expenses and other current assets	213.6			82.5
Income tax receivable	2.7			10.8
Deferred income taxes	8.8			27.8
Total current assets	1,765.5			1,731.7
Property, plant, and equipment, net of accumulated depreciation	1,909.6			1,864.4
Intangible assets, net	0.2			0.3
Goodwill	41.0			41.0
Deferred financing costs, net	9.1			11.2
Other long-term assets	27.0			17.2
Total assets	$	3,752.4		$	3,665.8
LIABILITIES AND EQUITY
Current liabilities:
Note payable and capital lease obligations	$	1.4		$	1.3
Accounts payable	421.2			377.9
Personnel accruals	49.5			45.8
Accrued taxes other than income taxes	23.0			31.5
Due to parent	15.8			0.1
Deferred revenue	1.8			0.7
Other current liabilities	61.3			44.2
Total current liabilities	574.0			501.5
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion	673.9			674.9
Accrued environmental liabilities, net of current portion	1.0			1.2
Deferred income taxes	600.4			601.7
Other long-term liabilities	48.8			51.1
Total long-term liabilities	1,324.1			1,328.9
Commitments and contingencies
Equity:
CVR stockholders’ equity:
Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 shares issued	0.9			0.9
Additional paid-in-capital	1,174.7			1,114.4
Retained earnings (deficit)	(75.2		)	76.2
Treasury stock, 98,610 shares at cost	(2.3		)	(2.3		)
Accumulated other comprehensive income (loss), net of tax	7.6			(0.6		)
Total CVR stockholders’ equity	1,105.7			1,188.6
Noncontrolling interest	748.6			646.8
Total equity	1,854.3			1,835.4
Total liabilities and equity	$	3,752.4		$	3,665.8

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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(unaudited)
	(in millions, except per share data)
Net sales	$	2,279.9		$	1,977.1		$	7,267.7		$	6,549.8
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)	2,066.7			1,744.4			6,332.6			5,343.5
Direct operating expenses (exclusive of depreciation and amortization)	136.8			128.4			380.3			345.2
Selling, general and administrative expenses (exclusive of depreciation and amortization)	31.8			27.7			86.2			85.0
Depreciation and amortization	37.8			36.2			113.7			105.4
Total operating costs and expenses	2,273.1			1,936.7			6,912.8			5,879.1
Operating income	6.8			40.4			354.9			670.7
Other income (expense):
Interest expense and other financing costs	(9.4		)	(11.7		)	(28.8		)	(39.6		)
Interest income	0.3			0.3			0.7			0.9
Gain on derivatives, net	25.7			72.5			171.1			173.0
Loss on extinguishment of debt	—			—			—			(26.1		)
Other income (expense), net	2.1			6.2			(0.1		)	6.5
Total other income	18.7			67.3			142.9			114.7
Income before income taxes	25.5			107.7			497.8			785.4
Income tax expense	4.2			29.5			118.8			222.8
Net income	21.3			78.2			379.0			562.6
Less: Net income attributable to noncontrolling interest	13.4			34.2			160.7			170.2
Net income attributable to CVR Energy stockholders	$	7.9		$	44.0		$	218.3		$	392.4

Basic earnings per share	$	0.09		$	0.51		$	2.51		$	4.52
Diluted earnings per share	$	0.09		$	0.51		$	2.51		$	4.52
Dividends declared per share	$	2.75		$	0.75		$	4.25		$	13.50

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

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
	(unaudited)
	(in millions)
Net income	$	21.3	$	78.2		$	379.0		$	562.6
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $5.2, $1.5, $5.2 and $2.4	8.0		2.3			8.0			3.7
Net gain reclassified into income on sale of available-for-sale securities, net of tax of $0, $(2.4), $0 and $(2.4)	—		(3.7		)	—			(3.7		)
Change in fair value of interest rate swap, net of tax of $0, $(0.1), $0 and $0	—		(0.2		)	(0.1		)	(0.1		)
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)	0.2		0.3			0.6			0.6
Total other comprehensive income (loss)	8.2		(1.3		)	8.5			0.5
Comprehensive income	29.5		76.9			387.5			563.1
Less: Comprehensive income attributable to noncontrolling interest	13.5		34.2			161.0			170.4
Comprehensive income attributable to CVR Energy stockholders	$	16.0	$	42.7		$	226.5		$	392.7

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 (Deficit)			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, 2013	86,929,660	$	0.9	$	1,114.4	$	76.2		$	(2.3	)	$	(0.6	)	$	1,188.6		$	646.8		$	1,835.4
June issuance of CVR Refining's common units to the public, net of $39.4 tax impact	—	—		60.3		—			—			—			60.3			88.6			148.9
Dividends paid to CVR Energy stockholders	—	—		—		(369.0		)	—			—			(369.0		)	—			(369.0		)
Distributions from CVR Partners to public unitholders	—	—		—		—			—			—			—			(39.0		)	(39.0		)
Distributions from CVR Refining to public unitholders	—	—		—		—			—			—			—			(109.5		)	(109.5		)
Share-based compensation	—	—		—		(0.7		)	—			—			(0.7		)	0.7			—
Net income	—	—		—		218.3			—			—			218.3			160.7			379.0
Net unrealized gain on available for sale securities, net of tax	—	—		—		—			—			8.0			8.0			—			8.0
Net gain on interest rate swaps, net of tax	—	—		—		—			—			0.2			0.2			0.3			0.5
Balance at September 30, 2014	86,929,660	$	0.9	$	1,174.7	$	(75.2	)	$	(2.3	)	$	7.6		$	1,105.7		$	748.6		$	1,854.3

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,
	2014			2013
	(unaudited)
	(in millions)
Cash flows from operating activities:
Net income	$	379.0		$	562.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	113.7			105.4
Allowance for doubtful accounts	(0.4		)	0.6
Amortization of deferred financing costs	2.1			2.2
Deferred income taxes	(28.5		)	(72.1		)
Loss on disposition of assets	0.2			—
Loss on extinguishment of debt	—			26.1
Share-based compensation	10.8			13.7
Gain on sale of available-for-sale securities	—			(6.1		)
Gain on derivatives, net	(171.1		)	(173.0		)
Current period settlements on derivative contracts	93.2			(3.9		)
Changes in assets and liabilities:
Accounts receivable	11.8			(30.9		)
Inventories	9.8			(152.2		)
Prepaid expenses and other current assets	13.1			12.3
Other long-term assets	(1.9		)	(0.4		)
Accounts payable	55.9			(21.3		)
Due to parent	15.7			42.9
Accrued income tax	8.1			1.0
Deferred revenue	1.1			(0.2		)
Other current liabilities	16.7			14.8
Accrued environmental liabilities	(0.2		)	(0.2		)
Other long-term liabilities	1.7			—
Net cash provided by operating activities	530.8			321.3
Cash flows from investing activities:
Capital expenditures	(171.4		)	(183.6		)
Proceeds from sale of assets	0.1			0.1
Purchase of available-for-sale securities	(78.3		)	(18.6		)
Proceeds from sale of available-for-sale securities	—			24.7
Net cash used in investing activities	(249.6		)	(177.4		)
Cash flows from financing activities:
Payment of capital lease obligations	(1.0		)	(0.9		)
Payments on senior secured notes	—			(243.4		)
Payment of financing costs	—			(0.4		)
Proceeds from CVR Refining's initial public offering, net of offering costs	—			655.7
Proceeds from CVR Refining's May 2013 offering, net of offering costs	—			393.6
Proceeds from the sale of CVR Refining's common units to AEPC	—			61.5
Proceeds from CVR Refining's June 2014 offering, net of offering costs	188.3			—
Proceeds from CVR Partners' secondary offering, net of offering costs	—			292.6
Redemption of common units	—			(0.2		)
Dividends to CVR Energy's stockholders	(369.0		)	(1,172.2		)
Distributions to CVR Refining's noncontrolling interest holders	(109.5		)	(37.7		)
Distributions to CVR Partners' noncontrolling interest holders	(39.0		)	(101.4		)
Net cash used in financing activities	(330.2		)	(152.8		)
Net decrease in cash and cash equivalents	(49.0		)	(8.9		)
Cash and cash equivalents, beginning of period	842.1			896.0
Cash and cash equivalents, end of period	$	793.1		$	887.1

CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)



	Nine Months Ended September 30,
	2014			2013
	(unaudited)
	(in millions)
Supplemental disclosures:
Cash paid for income taxes, net of refunds	$	123.4		$	251.1
Cash paid for interest net of capitalized interest of $8.2 and $2.0 in 2014 and 2013, respectively	$	18.4		$	36.6
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	$	20.1		$	32.0
Change in accounts payable related to construction in process additions	$	(12.7	)	$	(24.2	)

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, 2014

(unaudited)

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

Organization

The “Company,” “CVR Energy” 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, 2014, IEP owned approximately 82% of all of the outstanding shares of CVR.

CVR Partners, LP

On April 13, 2011, the Nitrogen Fertilizer Partnership completed its initial public offering (the “Nitrogen Fertilizer Partnership IPO”). 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 and through May 27, 2013, the Company recorded a 30% noncontrolling interest for the common units sold into the public market. On May 28, 2013, Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of the Company, 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.

Subsequent to the closing of the Secondary Offering and as of September 30, 2014, 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 manages the operations and activities of the Nitrogen Fertilizer Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The members of the board of directors of the general partner are not elected by the common unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Nitrogen Fertilizer Partnership IPO.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)

CVR Refining, LP

On January 23, 2013, the Refining Partnership completed its initial public offering (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 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 approximately 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 IEP, 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 prior to June 30, 2014, public security holders held approximately 29% of the total Refining Partnership common units (including units owned by IEP representing 4% of the total Refining Partnership common units), and CVR Refining Holdings, LLC (“CVR Refining Holdings”), a wholly-owned subsidiary of the Company, held approximately 71% of the total Refining Partnership common units.

On June 30, 2014, the Refining Partnership completed a second underwritten offering (the “Second Underwritten Offering”) by selling 6,500,000 common units to the public at a price of $26.07 per unit. The Refining Partnership paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. The Refining Partnership utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Subsequent to the closing of the Second Underwritten Offering and as of June 30, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately 67% of the total Refining Partnership common units.

On July 24, 2014, the Refining Partnership sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.

Subsequent to the closing of the underwriters' option of the Second Underwritten Offering and as of September 30, 2014, public security holders held approximately 34% of the total Refining Partnership common units (including units owned by IEP, representing 4% of the total Refining Partnership common units), and CVR Refining Holdings held approximately 66% of the total Refining Partnership common units. In addition, CVR Refining Holdings 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 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

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to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Refining Partnership.

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

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

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, 2013 audited consolidated financial statements and notes thereto included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2013, which was filed with the SEC on February 26, 2014 (the “2013 Form 10-K”).

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, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine month periods ended September 30, 2014 and 2013, changes in equity for the nine month period ended September 30, 2014 and cash flows of the Company for the nine month periods ended September 30, 2014 and 2013.

The preparation of the condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure

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of contingent assets and liabilities. Actual results could differ from those estimates. 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, 2014 or any other interim or annual period.

(2) Recent Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“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 Company adopted this standard prospectively as of January 1, 2014. The adoption of this standard resulted in a reclassification on the Condensed Consolidated Balance Sheets.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The standard is effective for interim and annual periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its 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 shares, 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, 2014, only restricted stock units and performance 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 Stock Units

A summary of restricted stock units grant activity and changes during the nine months ended September 30, 2014 is presented below:



	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2014	359,552		$	28.09
Granted	—		—
Vested	(40,926	)	20.75
Forfeited	(23,822	)	37.28
Non-vested at September 30, 2014	294,804		$	28.37

Through the LTIP, restricted shares have been granted to employees of the Company. The IEP Acquisition and related Transaction Agreement dated April 18, 2012 between CVR and IEP (“Transaction Agreement”) triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, 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 of $30.00 per share or the fair market value as determined at the most recent valuation date of December

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31 of each year. The awards, which generally vest over a three-year period, 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 during 2013, restricted stock units and dividend equivalent rights were granted to certain employees of CVR. The awards are expected to vest over three years, with one-third of the award vesting each year with the exception of awards granted to certain executive officers scheduled to vest over one year. Awards granted in December 2012 to Mr. Lipinski, the Company's Chief Executive Officer and President, were canceled in connection with the issuance of certain performance unit awards as discussed further below. Each restricted stock unit and dividend equivalent right 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.

As of September 30, 2014, there was approximately $2.1 million of total unrecognized compensation cost related to non-vested restricted stock units and associated dividend equivalent rights to be recognized over a weighted-average period of approximately 0.5 years. Total compensation expense for the three months ended September 30, 2014 and 2013 was approximately $0.7 million and $3.0 million, respectively, related to the awards. Total compensation expense for the nine months ended September 30, 2014 and 2013 was approximately $2.2 million and $12.1 million, respectively, related to the awards.

As of September 30, 2014 and December 31, 2013, the Company had a liability of $11.0 million and $8.9 million, respectively, for non-vested restricted stock unit awards and associated dividend equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

Performance Unit Awards

In December 2013, the Company entered into Performance Unit Award Agreements with Mr. Lipinski. Certain of the Performance Unit Awards were entered into in connection with the cancellation of Mr. Lipinski's December 2012 restricted stock unit award, as discussed above. In accordance with accounting guidance related to the modification of share-based and other compensatory award arrangements, the Company concluded that the cancellation and concurrent issuance of the performance awards created a substantive service period from the original grant date of the December 2012 restricted stock unit award through the end of the performance period for the related performance awards. Compensation cost for the related awards is being recognized over the substantive service period. Total compensation expense for the three and nine months ended September 30, 2014 related to the performance awards was approximately $0.1 million, and $3.8 million, respectively.

On June 30, 2014, the first award of Mr. Lipinski's Performance Unit Award Agreements vested. The Company paid Mr. Lipinski approximately $3.9 million on July 15, 2014 as a result of the vesting. As of September 30, 2014, the Company had a liability of $3.8 million for non-vested performance unit awards, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

Long-Term Incentive Plan – CVR Partners

Common Units and Phantom Units

In April 2011, the board of directors of the Nitrogen Fertilizer Partnership's 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. 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 2013 and during 2014, awards of phantom units and distribution equivalent rights were granted to certain employees of the Nitrogen Fertilizer Partnership and its subsidiaries and its general partner. The awards generally vest over three years with one-third of the award vesting each year. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash

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payment equal to (a) the average fair market value of one unit of the Nitrogen Fertilizer Partnership's common units for the first ten trading days in the month of vesting, plus (b) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership 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.

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, 2014 is presented below:



	Units		Weighted‑Average Grant-Date Fair Value
Non-vested at January 1, 2014	171,119		$	21.34
Granted	5,093		18.86
Vested	(5,085	)	21.39
Forfeited	(77,004	)	23.49
Non-vested at September 30, 2014	94,123		$	19.45

As of September 30, 2014, there was approximately $0.6 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.0 year. Total compensation expense recorded for the three months ended September 30, 2014 and 2013 related to the awards under the CVR Partners LTIP was approximately $(0.1) million and $0.4 million, respectively. Total compensation expense recorded for the nine months ended September 30, 2014 and 2013 related to the awards under the CVR Partners LTIP was approximately $0.4 million and $1.6 million, respectively.

As of September 30, 2014 and December 31, 2013, the Nitrogen Fertilizer Partnership had a liability of $0.6 million and $0.2 million, respectively, for cash settled non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

Performance-Based Phantom Units

In May 2014, the Nitrogen Fertilizer Partnership entered into a Phantom Unit Agreement with Mark A. Pytosh, its Chief Executive Officer and President, that included performance-based phantom units and distribution equivalent rights. Compensation cost for these awards is being recognized over the performance cycles of May 1, 2014 to December 31, 2014, January 1, 2015 to December 31, 2015 and January 1, 2016 to December 31, 2016, as the services are provided. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (a) the average closing price of the Nitrogen Fertilizer Partnership's common units for the first ten business days of the last month of the performance cycle, multiplied by a performance factor that is based upon the level of the Nitrogen Fertilizer Partnership’s production of UAN, and (b) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership from the grant date to and including the vesting date. Total compensation expense recorded for the three and nine months ended September 30, 2014 related to the award was not material. Assuming a target performance threshold, unrecognized compensation expense associated with the unvested phantom units at September 30, 2014 was approximately $0.3 million and is expected to be recognized over a weighted average period of 1.3 years.

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 (1) employees of the Refining Partnership and its subsidiaries, (2) employees of the general partner, (3) members of the board of directors of the general partner and (4) certain employees, consultants and directors of CRLLC and CVR Energy who perform services solely for the benefit of the Refining Partnership. 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. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000.

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In December 2013, awards of phantom units and distribution equivalent rights were granted to employees of the Refining Partnership and its subsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Refining Partnership. The awards are expected to vest over three years with one-third of the awards vesting each year. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (a) the average fair-market value of one unit of the Refining Partnership's common units for the first ten trading days in the month of vesting, plus (b) the per unit cash value of all distributions declared and paid by the Refining Partnership 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.

A summary of phantom unit activity and changes under the CVR Refining LTIP during the nine months ended September 30, 2014 is presented below:



	Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2014	187,177		$	21.55
Granted	—		—
Vested	—		—
Forfeited	(4,176	)	21.55
Non-vested at September 30, 2014	183,001		$	21.55

As of September 30, 2014, there was approximately $2.6 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.2 years. Total compensation expense recorded for the three and nine months ended September 30, 2014 related to the awards under the CVR Refining LTIP was approximately $0.6 million and $2.1 million, respectively.

As of September 30, 2014, the Refining Partnership had a liability of $2.1 million for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

Incentive Unit Awards

In December 2013 and during 2014, the Company granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC and CVR Energy. The awards generally vest over three years with one-third of the award vesting each year. Each incentive unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (a) the average fair market value of one unit of the Refining Partnership's common units for the first ten trading days in the month of vesting, plus (b) the per unit cash value of all distributions declared and paid by the Refining Partnership 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.

A summary of incentive unit activity and changes during the nine months ended September 30, 2014 is presented below:



	Incentive Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2014	251,431		$	22.62
Granted	4,320		23.02
Vested	—		—
Forfeited	(56,841	)	22.62
Non-vested at September 30, 2014	198,910		$	22.63

As of September 30, 2014, there was approximately $2.9 million of total unrecognized compensation cost related to non-vested incentive units and associated distribution equivalent rights to be recognized over a weighted-average period of

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approximately 1.2 years. Total compensation expense for the three and nine months ended September 30, 2014 related to the awards was approximately $0.6 million and $2.2 million, respectively.

As of September 30, 2014, the Company had a liability of $2.2 million for non-vested incentive units and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

(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. For all periods presented, inventories are valued at the lower of the first-in, first-out (“FIFO”) cost or market for fertilizer products, refined fuels and by-products. 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, 2014		December 31, 2013
	(in millions)
Finished goods	$	273.2	$	268.2
Raw materials and precious metals	165.0		177.0
In-process inventories	33.6		36.9
Parts and supplies	45.0		44.5
	$	516.8	$	526.6

(5) Property, Plant and Equipment

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



	September 30, 2014		December 31, 2013
	(in millions)
Land and improvements	$	37.2	$	36.1
Buildings	44.9		42.6
Machinery and equipment	2,410.3		2,312.5
Automotive equipment	20.6		19.2
Furniture and fixtures	20.0		18.3
Leasehold improvements	3.4		2.5
Aircraft	2.3		2.3
Railcars	7.9		7.9
Construction in progress	212.0		164.9
	2,758.6		2,606.3
Accumulated depreciation	849.0		741.9
Total property, plant and equipment, net	$	1,909.6	$	1,864.4

Capitalized interest recognized as a reduction in interest expense for the three months ended September 30, 2014 and 2013 totaled approximately $3.0 million and $0.8 million, respectively. Capitalized interest recognized as a reduction in interest expense for the nine months ended September 30, 2014 and 2013 totaled approximately $8.2 million and $2.0 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of

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approximately $24.8 million at both September 30, 2014 and December 31, 2013. Amortization of assets held under capital leases is included in depreciation expense.

(6) Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, pet coke expense, renewable identification numbers (“RINs”) expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.7 million and $1.3 million for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, cost of product sold excludes depreciation and amortization of approximately $4.7 million and $3.7 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 $34.4 million and $34.0 million for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, direct operating expenses exclude depreciation and amortization of approximately $104.4 million and $99.8 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 $1.7 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, selling, general and administrative expense excludes depreciation and amortization of approximately $4.6 million and $1.9 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 IEP, 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, 2014, the Company has recorded a liability of $15.8 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended September 30, 2014 and 2013, the Company paid $22.0 million and $95.0 million, respectively, to AEPC under the Tax Allocation Agreement. During the nine months ended September 30, 2014 and 2013, the Company paid $120.1 million and $234.0 million, respectively, 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, 2014, the Company had unrecognized tax benefits of approximately $55.0 million, of which $25.1 million, if recognized, would impact the Company’s effective tax rate. Approximately $14.2 million of unrecognized tax benefits were netted with deferred tax asset carryforwards. The remaining unrecognized tax benefits are included in other long-term liabilities in the Condensed Consolidated Balance Sheets. There are no unrecognized tax benefits expected to be settled within the next twelve months in income taxes payable. The Company has accrued interest of $5.5 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, 2014, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2011 through December 31, 2013 and in various individual states for the tax years ended December 31, 2009 through December 31, 2013.

The Company’s effective tax rate for the three and nine months ended September 30, 2014 was 16.5% and 23.9%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 39.6%. The Company’s effective tax rate for the three and nine months ended September 30, 2014 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 effective tax rate for the three months ended

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September 30, 2014 of 16.5% reflects the realization of additional domestic production activities deduction benefits of $1.7 million in the period. The Company’s effective tax rate for the three and nine months ended September 30, 2013 was 27.4% and 28.4% 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 was 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.

(8) Long-Term Debt

Long-term debt was as follows:



	September 30, 2014		December 31, 2013
	(in millions)
6.5% Senior Notes due 2022	$	500.0	$	500.0
CRNF credit facility	125.0		125.0
Capital lease obligations	48.9		49.9
Long-term debt	$	673.9	$	674.9

2022 Senior Notes

The Refining Partnership has $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022 (the “2022 Notes”) outstanding, which were issued by CVR Refining, LLC (“Refining LLC”) and Coffeyville Finance Inc. (“Coffeyville Finance”) on October 23, 2012. The 2022 Notes were issued at par 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, 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, 2014, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.

At September 30, 2014, the estimated fair value of the 2022 Notes was approximately $510.0 million. This estimate of fair value is Level 2 as it was determined by quotations obtained from a broker-dealer who makes a market in these and similar securities.

Amended and Restated Asset Based (ABL) Credit Facility

The Refining Partnership has a senior secured asset based revolving credit facility (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 has an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to 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 Refining Partnership and its 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. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017.

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(unaudited)

The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Refining Partnership and its respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments 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 Refining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of September 30, 2014.

As of September 30, 2014, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.7 million and had letters of credit outstanding of approximately $27.3 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of September 30, 2014.

Nitrogen Fertilizer Partnership Credit Facility

Coffeyville Resources Nitrogen Fertilizer, LLC (“CRNF”), as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, have 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, 2014. 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.

The credit facility requires the Nitrogen Fertilizer Partnership to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, and the ability to enter into sale-leaseback transactions or 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, 2014, 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 are 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 181 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 180 months remaining and will expire in September 2029.

Loss on Extinguishment of Debt

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 previously outstanding Second Lien Senior Secured Notes due 2017 (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.

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September 30, 2014

(unaudited)

(9) 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,
	2014		2013		2014		2013
	(in millions, except per share data)
Net income attributable to CVR Energy stockholders	$	7.9	$	44.0	$	218.3	$	392.4

Weighted-average shares of common stock outstanding - Basic	86.8		86.8		86.8		86.8
Weighted-average shares of common stock outstanding - Diluted	86.8		86.8		86.8		86.8

Basic earnings per share	$	0.09	$	0.51	$	2.51	$	4.52
Diluted earnings per share	$	0.09	$	0.51	$	2.51	$	4.52

There were no dilutive awards outstanding during the three and nine months ended September 30, 2014 and 2013, as all unvested awards under the LTIP were liability-classified awards. See Note 3 ("Share-Based Compensation").

(10) 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, 2014	$	2.4	$	65.9
Year Ending December 31,
2015	8.1		120.9
2016	6.7		114.1
2017	4.4		112.0
2018	3.2		112.1
Thereafter	5.3		902.5
	$	30.1	$	1,427.5

(1)

This amount includes approximately $929.8 million payable ratably over seventeen years pursuant to petroleum transportation service agreements between Coffeyville Resources Refining & Marketing, LLC (“CRRM”) and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together, “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.

CVR leases various equipment, including railcars and real properties, under long-term operating leases which expire at various dates. For each of the three months ended September 30, 2014 and 2013, lease expense totaled approximately $2.4 million. For the nine months ended September 30, 2014 and 2013, lease expense totaled approximately $6.9 million and $7.0

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(unaudited)

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. For the three months ended September 30, 2014 and 2013, total expense of approximately $31.2 million and $28.3 million, respectively, was incurred related to long-term commitments. For the nine months ended September 30, 2014 and 2013, total expense of approximately $100.0 million and $94.6 million, respectively, was incurred related to long-term commitments.

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”). 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. The Vitol Agreement was extended for a one-year Renewal Term through December 31, 2015.

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. Except as described below, there were no new proceedings or material developments in proceedings that CVR previously reported in its 2013 Form 10-K or in its Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 (“2014 Q1 Form 10-Q”) and June 30, 2014 (“2014 Q2 Form 10-Q”), which were filed with the SEC on May 2, 2014 and August 1, 2014, respectively. 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 will prove to be 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 fees allegedly due to GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock, made by Carl C. Icahn and certain of his affiliates. On September 8, 2014, the court (in its decision granting GS’s motion for summary judgment against CVR) directed the court clerk to enter judgment against CVR in the amount of approximately $22.6 million, which has been fully accrued as of September 30, 2014. CVR filed its notice of appeal on October 3, 2014 and intends to vigorously pursue the appeal.

On August 10, 2012, Deutsche Bank (“DB”) filed suit against CVR in state court in New York, alleging that CVR failed to pay DB 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 Carl C. Icahn and certain of his affiliates. On September 8, 2014, the court (in its decision granting DB’s motion for summary judgment against CVR) directed the court clerk to enter judgment against CVR in the amount of approximately $22.7 million, which has been fully accrued as of September 30, 2014. CVR filed its notice of appeal on October 3, 2014 and intends to vigorously pursue the appeal. On October 27, 2014, CVR paid the judgment to DB, subject to a right of refund if it is successful on appeal.

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September 30, 2014

(unaudited)

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 can include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the Oil Pollution Act generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.

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, and 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.

As previously reported, the petroleum and nitrogen fertilizer businesses are party to, or otherwise subject to administrative orders and consent decrees with federal, state and local environmental authorities, as applicable, addressing corrective actions under RCRA, the Clean Air Act and the Clean Water Act. The petroleum business also is subject to (i) the Mobile Source Air Toxic II (“MSAT II”) rule which requires reductions of benzene in gasoline; (ii) 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; and (iii) “Tier 3” gasoline sulfur standards. Except as otherwise described below, there have been no new developments or material changes to the environmental accruals or expected capital expenditures related to compliance with the foregoing environmental matters from those provided in CVR's 2013 Form 10-K, 2014 Q1 Form 10-Q or 2014 Q2 Form 10-Q. 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 or referenced herein 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.

At September 30, 2014, the Company’s Condensed Consolidated Balance Sheet included total environmental accruals of $1.2 million, compared with $1.5 million at December 31, 2013. 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.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended September 30, 2014 and 2013, capital expenditures were approximately $23.1 million and $35.5 million, respectively. For the nine months ended September 30, 2014 and 2013, capital expenditures were approximately $83.3 million and $73.5 million, respectively. These expenditures were incurred for environmental compliance and efficiency of the operations.

The cost of RINs for the three months ended September 30, 2014 and 2013 was approximately $18.5 million and $57.4 million, respectively. The cost of RINs for the nine months ended September 30, 2014 and 2013 was approximately $82.3 million and $155.0 million, respectively. As of September 30, 2014 and December 31, 2013, the petroleum business’ biofuel blending

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(unaudited)

obligation was approximately $36.3 million and $17.4 million, respectively, which was recorded in other current liabilities on the Condensed Consolidated Balance Sheets.

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%. Two such entities, ACF Industries LLC (“ACF”) and Federal-Mogul, are the sponsors 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, 2014 and December 31, 2013. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be underfunded by approximately $442.6 million and $591.8 million as of September 30, 2014 and December 31, 2013, respectively. 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 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.

(11) Coffeyville Refinery Incident

On July 29, 2014, the Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employee who was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System, which was directly caused by the fire. The Coffeyville refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. This interruption adversely impacted production of refined products for the petroleum business in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the three and nine months ended September 30, 2014 were approximately $5.5 million.

The Refining Partnership maintains property damage insurance policies which have an associated deductible of $5.0 million for the Coffeyville refinery. The Refining Partnership anticipates amounts in excess of the $5.0 million deductible will be recoverable under the property insurance policies. As of September 30, 2014, the Refining Partnership recorded an insurance receivable related to the incident of approximately $0.5 million, which is included in prepaid expenses and other current assets in the Condensed Consolidated Balance Sheet. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization). The Refining Partnership also maintains workers' compensation insurance with a $0.5 million per accident deductible.

During the outage at the Coffeyville refinery as discussed above, the Refining Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred approximately $5.5 million in turnaround expenses for the three and nine months ended September 30, 2014.

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(unaudited)

(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, 2014 and December 31, 2013:



	September 30, 2014
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Cash equivalents	$	69.0	$	—		$	—	$	69.0
Other current assets (investments)	89.4		4.4			—		93.8
Other current assets (other derivative agreements)	—		53.2			—		53.2
Other long-term assets (other derivative agreements)	—		8.6			—		8.6
Total Assets	$	158.4	$	66.2		$	—	$	224.6
Other current liabilities (interest rate swaps)	—		(0.9		)	—		(0.9		)
Other current liabilities (biofuel blending obligations)	—		(9.9		)	—		(9.9		)
Other long-term liabilities (interest rate swaps)	—		(0.3		)	—		(0.3		)
Total Liabilities	$	—	$	(11.1	)	$	—	$	(11.1	)



	December 31, 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)	—		0.9			—		0.9
Other long-term assets (other derivative agreements)	—		0.1			—		0.1
Total Assets	$	81.0	$	1.0		$	—	$	82.0
Other current liabilities (other derivative agreements)	—		(15.3		)	—		(15.3		)
Other current liabilities (interest rate swaps)	—		(0.9		)	—		(0.9		)
Other current liabilities (biofuel blending obligation)	—		(16.2		)	—		(16.2		)
Other long-term liabilities (other derivative agreements)	—		(1.8		)	—		(1.8		)
Other long-term liabilities (interest rate swaps)	—		(1.0		)	—		(1.0		)
Total Liabilities	$	—	$	(35.2	)	$	—	$	(35.2	)

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September 30, 2014

(unaudited)

As of September 30, 2014 and December 31, 2013, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s cash equivalents, investments, 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, certain investments and the uncommitted biofuel blending obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, are considered Level 2 inputs. The Nitrogen Fertilizer Partnership has interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. The Company's investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices. As of September 30, 2014, the aggregate cost basis for the Company's available-for-sale securities is approximately $76.2 million. The Company recognized an unrealized gain of $13.2 million on the available-for-sale securities for the three and nine months ended September 30, 2014, which is recorded in accumulated other comprehensive income (loss) (“AOCI”). The Company had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2014.

(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,
	2014		2013		2014		2013
	(in millions)
Current period settlements on derivative contracts	$	38.2	$	33.9	$	93.2	$	(3.9	)
Gain on derivatives, net	25.7		72.5		171.1		173.0

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 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 other current assets or other current liabilities within the Condensed Consolidated Balance Sheets. From time to time, the Refining Partnership may be required to deposit additional funds into this margin account. There were no open commodity positions as of September 30, 2014. For the three months ended September 30, 2014 and 2013, the Refining Partnership recognized net gains of $43,000 and $0.1 million, respectively. For the nine months ended September 30, 2014 and 2013, the Refining Partnership recognized net losses of $0.3 million and $2.3 million, respectively. These recognized net gains and losses are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

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September 30, 2014

(unaudited)

Commodity Swaps

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, 2014 and December 31, 2013, the Refining Partnership had open commodity hedging instruments consisting of 9.8 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at September 30, 2014 was a net unrealized gain of $61.8 million, of which $53.2 million was included in current assets and $8.6 million was included in non-current assets. For the three months ended September 30, 2014 and 2013, the Refining Partnership recognized net gains of $25.7 million and $72.4 million, respectively. For the nine months ended September 30, 2014 and 2013, the Refining Partnership recognized net gains of $171.4 million and $175.3 million, respectively. These recognized net gains are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

Nitrogen Fertilizer Partnership Interest Rate Swaps

CRNF is subject to 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, as further discussed in 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 facility. At September 30, 2014, the effective rate was approximately 4.56%. 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 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 swaps re-classed from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.3 million for each of the three months ended September 30, 2014 and 2013, respectively. For the three months ended September 30, 2014 and 2013, the Nitrogen Fertilizer Partnership recognized decreases in fair value of the interest rate swap agreements of $0 and $0.3 million, respectively, which were unrealized in AOCI. The realized loss on the interest rate swaps re-classed from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.8 million for each of the nine months ended September 30, 2014 and 2013, respectively. For each of the nine months ended September 30, 2014 and 2013, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0.1 million, which were 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, 2014, 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,

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)

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, 2014 and December 31, 2013. 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, 2014 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, 2014
Description	Gross Current Assets		Gross Amounts Offset		Net Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	53.2	$	—	$	53.2	$	—	$	53.2
Total	$	53.2	$	—	$	53.2	$	—	$	53.2



	As of September 30, 2014
Description	Gross Non-Current Assets		Gross Amounts Offset		Net Non-Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	8.6	$	—	$	8.6	$	—	$	8.6
Total	$	8.6	$	—	$	8.6	$	—	$	8.6

The offsetting assets and liabilities for the Refining Partnership’s derivatives as of December 31, 2013 are recorded as current assets, non-current assets, current liabilities and non-current liabilities in prepaid expenses and other current assets, other long-term assets, other current liabilities and other long-term liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:



	As of December 31, 2013
Description	Gross Current Assets		Gross Amounts Offset			Net Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	4.3	$	(3.4	)	$	0.9	$	—	$	0.9
Total	$	4.3	$	(3.4	)	$	0.9	$	—	$	0.9

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)



	As of December 31, 2013
Description	Gross Non-Current Assets		Gross Amounts Offset		Net Non-Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	0.1	$	—	$	0.1	$	—	$	0.1
Total	$	0.1	$	—	$	0.1	$	—	$	0.1



	As of December 31, 2013
Description	Gross Current Liabilities		Gross Amounts Offset			Net Current Liabilities Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	31.4	$	(16.1	)	$	15.3	$	—	$	15.3
Total	$	31.4	$	(16.1	)	$	15.3	$	—	$	15.3



	As of December 31, 2013
Description	Gross Non-Current Liabilities		Gross Amounts Offset			Net Non-Current Liabilities Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	1.9	$	(0.1	)	$	1.8	$	—	$	1.8
Total	$	1.9	$	(0.1	)	$	1.8	$	—	$	1.8

(14) Related Party Transactions

Icahn Enterprises

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, 2014, IEP owned approximately 82% of all common shares outstanding.

The following is a summary of the quarterly and special dividends paid to the Company's stockholders, including IEP, during 2014:



	December 31, 2013		March 31, 2014		June 30, 2014		July 17, 2014		Total Dividends Paid in 2014
	(in millions, except per share data)
	Quarterly		Quarterly		Quarterly		Special
Amount paid to IEP	$	53.4	$	53.4	$	53.4	$	142.4	$	302.6
Amounts paid to public stockholders	11.7		11.7		11.7		31.3		66.4
Total amount paid	$	65.1	$	65.1	$	65.1	$	173.7	$	369.0
Per common share	$	0.75	$	0.75	$	0.75	$	2.00	$	4.25
Shares outstanding	86.8		86.8		86.8		86.8

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)

American Railcar Industries, Inc.

In the second quarter of 2014, the Nitrogen Fertilizer Partnership entered into a contract to purchase approximately 50 new UAN railcars from American Railcar Industries, Inc. (“ARI”), an affiliate of IEP, for approximately $6.7 million. The Nitrogen Fertilizer Partnership has received 25 new UAN railcars in the third quarter of 2014 and expects the delivery of the remaining new railcars from ARI will be completed by December 2014. During each of the three and nine months ended September 30, 2014, the Nitrogen Fertilizer Partnership paid approximately $3.3 million for the delivered railcars.

ARI performed railcar maintenance for the Nitrogen Fertilizer Partnership starting in 2014. The expenses associated with this maintenance were approximately $50,000 for each of the three and nine months ended September 30, 2014.

Tax Allocation Agreement

As of September 30, 2014, the Company has recorded approximately $15.8 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended September 30, 2014 and 2013, the Company paid $22.0 million and $95.0 million, respectively, to AEPC under the Tax Allocation Agreement. During the nine months ended September 30, 2014 and 2013, the Company paid $120.1 million and $234.0 million, respectively, 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 and subsequent periods. The Company paid Insight Portfolio Group approximately $0.2 million and $0 during the three months ended September 30, 2014 and 2013, respectively. The Company paid Insight Portfolio Group approximately $0.3 million and $0.1 million during the nine months ended September 30, 2014 and 2013, respectively. The Company may purchase a variety of goods and services as a member 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.

(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 $1.9 million and $1.6 million for the three months ended September 30, 2014 and 2013, respectively.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)

Intercompany net sales included in petroleum net sales were approximately $6.5 million and $7.0 million for the nine months ended September 30, 2014 and 2013, respectively.

The petroleum segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases described below under “Nitrogen Fertilizer” of approximately $0.1 million and $0.8 million for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, the petroleum segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) of approximately $6.9 million and $4.7 million, respectively. The petroleum segment recorded intercompany revenue for hydrogen sales of approximately $0 and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, the petroleum segment recorded intercompany revenue for hydrogen sales of approximately $0 and $0.6 million, 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 $2.1 million and $2.2 million for the three months ended September 30, 2014 and 2013, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $6.6 million and $7.4 million for the nine months ended September 30, 2014 and 2013, respectively.

Pursuant to the feedstock agreement, the Company’s segments have the right to transfer 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, 2014 and 2013, the net sales generated from intercompany hydrogen sales were $0.1 million and $0.8 million, respectively. For the nine months ended September 30, 2014 and 2013, the net sales generated from intercompany hydrogen sales were $6.9 million and $4.7 million, respectively. For the three months ended September 30, 2014 and 2013, the nitrogen fertilizer segment also recognized approximately $0 and $0.3 million, respectively, of cost of product sold related to the transfer of excess hydrogen. For the nine months ended September 30, 2014 and 2013, the nitrogen fertilizer segment also recognized approximately $0 and $0.6 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.

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.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Net sales
Petroleum	$	2,215.2		$	1,910.5		$	7,056.9		$	6,322.6
Nitrogen Fertilizer	66.7			69.2			224.3			239.4
Intersegment elimination	(2.0		)	(2.6		)	(13.5		)	(12.2		)
Total	$	2,279.9		$	1,977.1		$	7,267.7		$	6,549.8
Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	2,053.7		$	1,734.7		$	6,289.6		$	5,317.0
Nitrogen Fertilizer	15.4			13.0			56.6			39.2
Intersegment elimination	(2.4		)	(3.3		)	(13.6		)	(12.7		)
Total	$	2,066.7		$	1,744.4		$	6,332.6		$	5,343.5
Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	110.6		$	104.7		$	303.0		$	274.5
Nitrogen Fertilizer	26.1			23.7			77.2			70.7
Other	0.1			—			0.1			—
Total	$	136.8		$	128.4		$	380.3		$	345.2
Depreciation and amortization
Petroleum	$	29.7		$	28.8		$	89.9		$	85.2
Nitrogen Fertilizer	6.8			6.6			20.3			18.5
Other	1.3			0.8			3.5			1.7
Total	$	37.8		$	36.2		$	113.7		$	105.4
Operating income
Petroleum	$	3.9		$	23.4		$	320.4		$	588.1
Nitrogen Fertilizer	14.4			21.3			56.3			95.2
Other	(11.5		)	(4.3		)	(21.8		)	(12.6		)
Total	$	6.8		$	40.4		$	354.9		$	670.7
Capital expenditures
Petroleum	$	48.9		$	60.7		$	154.2		$	140.8
Nitrogen fertilizer	6.0			4.0			13.5			35.8
Other	1.6			4.3			3.7			7.0
Total	$	56.5		$	69.0		$	171.4		$	183.6

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2014

(unaudited)



	As of September 30, 2014		As of December 31, 2013
	(in millions)
Total assets
Petroleum	$	2,691.7	$	2,533.3
Nitrogen Fertilizer	562.1		593.5
Other	498.6		539.0
Total	$	3,752.4	$	3,665.8
Goodwill
Petroleum	$	—	$	—
Nitrogen Fertilizer	41.0		41.0
Other	—		—
Total	$	41.0	$	41.0

(16) Subsequent Events

Dividend

On October 29, 2014, the board of directors of the Company declared a cash dividend for the third quarter of 2014 to the Company’s stockholders of $0.75 per share, or $65.1 million in aggregate. The dividend will be paid on November 17, 2014 to stockholders of record at the close of business on November 10, 2014. IEP will receive $53.4 million in respect of its 82% ownership interest in the Company’s shares.

Nitrogen Fertilizer Partnership Distribution

On October 29, 2014, the board of directors of the Nitrogen Fertilizer Partnership’s general partner declared a cash distribution for the third quarter of 2014 to the Nitrogen Fertilizer Partnership’s unitholders of $0.27 per common unit, or $19.7 million in aggregate. The cash distribution will be paid on November 17, 2014 to unitholders of record at the close of business on November 10, 2014. The Company will receive $10.5 million in respect of its Nitrogen Fertilizer Partnership common units.

Refining Partnership Distribution

On October 29, 2014, the board of directors of the Refining Partnership’s general partner declared a cash distribution for the third quarter of 2014 to the Refining Partnership’s unitholders of $0.54 per common unit, or $79.7 million in aggregate. The cash distribution will be paid on November 17, 2014 to unitholders of record at the close of business on November 10, 2014. The Company will receive $52.5 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 of our financial condition and results of operations 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, 2013 filed with the Securities and Exchange Commission (“SEC”) on February 26, 2014 (the “2013 Form 10-K”). Results of operations for the three and nine months ended September 30, 2014 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, including statements concerning contemplated transactions and strategic plans, expectations and objectives for future operations. Forward-looking statements 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 or operational performance, future dividends, future capital sources and capital expenditures; 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:


•	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;


•	the effects of transactions involving forward and derivative instruments;


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


•	changes in laws, regulations and policies with respect to the export of crude oil or other hydrocarbons;


•	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;

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


•	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. As of September 30, 2014, IEP Energy LLC and certain affiliates (collectively “IEP”) owned approximately 82% of our outstanding common stock.

We operate under two business segments: petroleum and nitrogen fertilizer, which are referred to in this document 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, 2014, we owned the general partner and approximately 66% of the common units of the Refining Partnership. The petroleum business

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consists of a 115,000 bpcd rated capacity complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpcd rated capacity medium complexity crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). In addition, its supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 60,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and at throughput terminals on Magellan and NuStar’s refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 336 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 $50.0 million, excluding capitalized interest, on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. As of September 30, 2014, approximately $40.6 million, excluding capitalized interest, 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 premium to WTI for the third quarter of 2014 was $0.10 per barrel compared to a discount of $1.25 per barrel in the third quarter of 2013.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At September 30, 2014, 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, 2014, the nitrogen fertilizer business produced 223,505 and 704,144 tons of UAN and 99,770 and 283,044 tons of ammonia, respectively. For the three and nine months ended September 30, 2014, approximately 89% and 92% of the produced and purchased ammonia tons were upgraded into UAN.

The Nitrogen Fertilizer Partnership intends to continue to expand the nitrogen fertilizer business’ existing asset base to execute its growth strategy, which includes expanded production of UAN and acquiring additional infrastructure and production assets. The Nitrogen Fertilizer Partnership completed a significant two-year plant expansion in February 2013, which increased its UAN production capacity by 400,000 tons, or approximately 50%, per year. The Nitrogen Fertilizer Partnership expects to upgrade 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. By using pet coke as the primary raw material feedstock instead of natural gas, we believe the nitrogen fertilizer business has historically been one of the lowest cost producers and marketers of UAN and ammonia fertilizers in North America. The nitrogen fertilizer business currently purchases

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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. 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.

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 unit, resulting in gross proceeds of $600.0 million. Of the common units issued, 4,000,000 units were purchased by IEP. 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 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, CVR Refining GP, LLC, 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 IEP, 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.”

The Refining Partnership utilized proceeds of approximately $394.0 million from the Underwritten Offering (including proceeds from the exercise of 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.

Following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding Refining Partnership common units (including units owned by IEP, 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 the Refining Partnership's general partner.

Refining Partnership Second Underwritten Offering

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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. 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.

Following the closing of the Secondary Offering and as of September 30, 2014, 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. In 2013, the Wynnewood refinery was subject to the RFS for the first time. However, because the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year, the Wynnewood refinery petitioned the EPA as a “small refinery” for hardship relief from the RFS requirements in 2013 based on the “disproportionate economic hardship” of the rule on the Wynnewood refinery. The EPA denied the petition in a letter dated September 5, 2014. During 2013, the cost of RINs became extremely volatile as the EPA's proposed renewable fuel volume mandates approached the “blend wall.” The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the proposed annual renewable fuel percentage standards for 2014, which acknowledge the blend wall and are generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 proposed percentage standards were published; however, RIN prices have remained volatile and have increased in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following the publication of the final 2014 annual renewable fuel percentage standards.

The cost of RINs for the three months ended September 30, 2014 and 2013 was approximately $18.5 million and $57.4 million, respectively. The cost of RINs for the nine months ended September 30, 2014 and 2013 was approximately $82.3 million and $155.0 million, respectively. The future cost of RINs for the petroleum business is difficult to estimate. In particular, the cost

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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 $100.0 million to $125.0 million for the year ending December 31, 2014.

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.

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

Although the 2-1-1 crack spread is a benchmark for the refinery margin, because the refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and their product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. The Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutene, gasoline components, and normal butane are also typically used. We measure the cost advantage of the crude oil slate by calculating the spread between the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. The refinery margin can be impacted significantly by the consumed crude oil differential. The consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the 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 its 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, 2014, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $7.1 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.

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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. During the outage at the Coffeyville refinery as discussed further below, the petroleum business accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million of turnaround expenses for the three and nine months ended September 30, 2014. The Wynnewood Refinery completed a turnaround in December 2012. Its next turnaround is scheduled to begin in late 2016.

During the three months ended September 30, 2013, the fluid catalytic cracking unit (“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 and nine months ended September 30, 2013. Additionally, the Refining Partnership incurred approximately $20.8 million in costs to repair the FCCU during the three and nine 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.

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 20 year 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.

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Natural gas is the most significant raw material required in its competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility. However, calendar years 2012 and 2013 were two of the lowest priced years for natural gas prices as compared to the last 10 years. This pricing and volatility has a direct impact on the nitrogen fertilizer business’ competitors’ cost of producing nitrogen fertilizer.

In order to assess the operating performance of the nitrogen fertilizer business, the nitrogen fertilizer business calculates the product pricing at gate as an input to determine its operating margin. Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons, and is shown in order to provide a pricing measure that is comparable across the fertilizer industry.

The nitrogen fertilizer business and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to out-of-region competitors in serving the U.S. farm belt agricultural market. In 2013, approximately 53% of the corn planted in the United States was grown within a $45 per UAN ton freight train rate of the nitrogen fertilizer plant. The nitrogen fertilizer business is therefore able to cost-effectively sell substantially all of its products in the higher margin agricultural market, whereas a significant portion of its competitors’ revenues are derived from the lower margin industrial market. The nitrogen fertilizer business’ products leave the plant either in railcars for destinations located principally on the Union Pacific Railroad or in trucks for direct shipment to customers. The nitrogen fertilizer business does not currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges. The nitrogen fertilizer business estimates that its 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. Going forward, as a result of the UAN expansion process completion, the nitrogen fertilizer business expects to upgrade substantially all of its ammonia production into UAN for as long as it makes economic sense to do so. The value of nitrogen fertilizer products is also an important consideration in understanding the nitrogen fertilizer business’ results.

The nitrogen fertilizer business’ largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. For the three months ended September 30, 2014 and 2013, the nitrogen fertilizer business spent approximately $3.4 million and $3.5 million, respectively, for pet coke, which equaled an average cost per ton of $29 and $30, respectively. For the nine months ended September 30, 2014 and 2013, the nitrogen fertilizer business spent approximately $10.2 million and $10.9 million, respectively, for pet coke, which equaled an average cost per ton of $28 and $30, respectively.

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 full facility turnaround every two to three years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $5.0 million per turnaround. The Nitrogen Fertilizer Partnership is planning to undergo the next full facility turnaround in the second half of 2015. A less involved facility shutdown was performed during the second quarter of 2014 and included both the installation of a waste heat boiler and the completion of several key tasks in order to upgrade the pressure swing adsorption ("PSA") unit, which is projected to increase hydrogen recovery enough to allow the nitrogen fertilizer business to produce approximately 7,000 to 9,000 additional tons of ammonia 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

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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, which was subsequently expanded to $250.0 million on October 29, 2014 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 (“Vitol”) entered into an Amended and Restated Crude Oil Supply Agreement (the “Vitol Agreement”). Under the agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps the petroleum business to reduce its 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. The Vitol Agreement was extended for a one-year Renewal Term through December 31, 2015.

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 presented and discussed below.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Loss on extinguishment of debt (a)	$	—		$	—		$	—		$	26.1
Share-based compensation (b)	2.0			3.4			10.8			13.7
Gain on derivatives, net	(25.7		)	(72.5		)	(171.1		)	(173.0		)
Major scheduled turnaround expenses (c)	5.5			—			5.5			—

_______________________________________

(a) Represents for 2013, the write-off of previously deferred financing costs, unamortized original issue discount and the premium paid related to the extinguishment of CRLLC's Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes”).

(b) Represents impact of share-based compensation awards.

(c) Represents expense associated with certain major scheduled turnaround activities performed at the Coffeyville refinery during the third quarter of 2014.

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, the noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the offering in the second quarter of 2013 and prior to June 30, 2014 was approximately 29%. Upon completion of the Second Underwritten Offering on June 30, 2014 and through July 23, 2014, the noncontrolling interest reflected in our condensed consolidated financial statements was approximately 33%. On July 24, 2014, upon exercise of the underwriters option associated with the Second Underwritten Offering, the noncontrolling interest reflected in our condensed consolidated financial statements is approximately 34%. Additionally, as a result of the Nitrogen Fertilizer Partnership's Secondary Offering, the

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noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the offering in the second quarter of 2013 and as of September 30, 2014 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.

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 distribution 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 board of directors of the Nitrogen Fertilizer Partnership’s general partner calculates available cash for distribution 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's general partner 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.

The following is a summary of cash distributions paid to the Nitrogen Fertilizer Partnership unitholders during 2014 for the respective quarters to which the distributions relate:



	December 31, 2013		March 31, 2014		June 30, 2014		Total Cash Distributions Paid in 2014
	($ in millions, except per common unit data)
Amount paid to CRLLC	$	16.7	$	14.8	$	12.8	$	44.4
Amounts paid to public unitholders	14.7		13.0		11.3		39.0
Total amount paid	$	31.4	$	27.8	$	24.1	$	83.4
Per common unit	$	0.43	$	0.38	$	0.33	$	1.14
Common units outstanding	73.1		73.1		73.1

On October 29, 2014, the board of directors of the Nitrogen Fertilizer Partnership’s general partner declared a cash distribution for the third quarter of 2014 to the Nitrogen Fertilizer Partnership’s unitholders of $0.27 per common unit or $19.7 million in aggregate. The cash distribution will be paid on November 17, 2014 to unitholders of record at the close of business on November 10, 2014. We will receive $10.5 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 distribution 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's general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions at all.

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The following is a summary of cash distributions paid to the Refining Partnership unitholders during 2014 for the respective quarters to which the distributions relate:



	December 31, 2013		March 31, 2014		June 30, 2014		Total Cash Distributions Paid in 2014
	($ in millions, except per common unit data)
Amount paid to CVR Refining Holdings, LLC	$	47.1	$	102.8	$	93.4	$	243.3
Amounts paid to public unitholders	19.3		41.9		48.3		109.5
Total amount paid	$	66.4	$	144.7	$	141.7	$	352.8
Per common unit	$	0.45	$	0.98	$	0.96	$	2.39
Common units outstanding	147.6		147.6		147.6

On October 29, 2014, the board of directors of the Refining Partnership’s general partner declared a cash distribution for the third quarter of 2014 to the Refining Partnership’s unitholders of $0.54 per common unit or $79.7 million in aggregate. The cash distribution will be paid on November 17, 2014 to unitholders of record at the close of business on November 10, 2014. We will receive $52.5 million in respect of our common units.

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.

The following is a summary of the quarterly and special dividends paid to the Company's stockholders during 2014:



	December 31, 2013		March 31, 2014		June 30, 2014		July 17, 2014		Total Dividends Paid in 2014
	(in millions, except per share data)
	Quarterly		Quarterly		Quarterly		Special
Amount paid to IEP	$	53.4	$	53.4	$	53.4	$	142.4	$	302.6
Amounts paid to public stockholders	11.7		11.7		11.7		31.3		66.4
Total amount paid	$	65.1	$	65.1	$	65.1	$	173.7	$	369.0
Per common share	$	0.75	$	0.75	$	0.75	$	2.00	$	4.25
Shares outstanding	86.8		86.8		86.8		86.8

On October 29, 2014, our board of directors declared a dividend for the third quarter of 2014 of $0.75 per share, or $65.1 million in aggregate. The dividend will be paid on November 17, 2014 to stockholders of record at the close of business on November 10, 2014.

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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, 2014 and 2013. 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, 2013, is unaudited.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions, except per share data)
Consolidated Statement of Operations Data
Net sales	$	2,279.9		$	1,977.1		$	7,267.7		$	6,549.8
Cost of product sold(1)	2,066.7			1,744.4			6,332.6			5,343.5
Direct operating expenses(1)	136.8			128.4			380.3			345.2
Selling, general and administrative expenses(1)	31.8			27.7			86.2			85.0
Depreciation and amortization(1)	37.8			36.2			113.7			105.4
Operating income	6.8			40.4			354.9			670.7
Interest expense and other financing costs	(9.4		)	(11.7		)	(28.8		)	(39.6		)
Interest income	0.3			0.3			0.7			0.9
Gain on derivatives, net	25.7			72.5			171.1			173.0
Loss on extinguishment of debt	—			—			—			(26.1		)
Other income (expense), net	2.1			6.2			(0.1		)	6.5
Income before income tax expense	25.5			107.7			497.8			785.4
Income tax expense	4.2			29.5			118.8			222.8
Net income	21.3			78.2			379.0			562.6
Less: Net income attributable to noncontrolling interest	13.4			34.2			160.7			170.2
Net income attributable to CVR Energy stockholders	$	7.9		$	44.0		$	218.3		$	392.4

Basic earnings per share	$	0.09		$	0.51		$	2.51		$	4.52
Diluted earnings per share	$	0.09		$	0.51		$	2.51		$	4.52
Dividends declared per share	$	2.75		$	0.75		$	4.25		$	13.50

Adjusted EBITDA(2)	$	90.5		$	42.4		$	391.9		$	549.7

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



	As of September 30, 2014		As of December 31, 2013
			(audited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	793.1	$	842.1
Working capital	1,191.5		1,230.2
Total assets	3,752.4		3,665.8
Total debt, including current portion	675.3		676.2
Total CVR Energy stockholders’ equity	1,105.7		1,188.6

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	125.3		$	(59.7	)	$	530.8		$	321.3
Investing activities	(56.6		)	(44.3		)	(249.6		)	(177.4		)
Financing activities	(274.3		)	(143.4		)	(330.2		)	(152.8		)
Net cash flow	$	(205.6	)	$	(247.4	)	$	(49.0	)	$	(8.9	)
Other Financial Data
Capital expenditures for property, plant and equipment	$	56.5		$	69.0		$	171.4		$	183.6


(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,
	2014		2013		2014		2013
	(in millions)
Depreciation and amortization excluded from cost of product sold	$	1.7	$	1.3	$	4.7	$	3.7
Depreciation and amortization excluded from direct operating expenses	34.4		34.0		104.4		99.8
Depreciation and amortization excluded from selling, general and administrative expenses	1.7		0.9		4.6		1.9
Total depreciation and amortization	$	37.8	$	36.2	$	113.7	$	105.4

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(2)

EBITDA and Adjusted EBITDA. EBITDA represents net income before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, loss on disposition of fixed assets, (gain) loss on derivatives, net, current period settlements on derivative contracts and loss on extinguishment of debt. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Net income attributable to CVR Energy stockholders	$	7.9		$	44.0		$	218.3		$	392.4
Add:
Interest expense and other financing costs, net of interest income	9.1			11.4			28.1			38.7
Income tax expense	4.2			29.5			118.8			222.8
Depreciation and amortization	37.8			36.2			113.7			105.4
EBITDA adjustments included in noncontrolling interest	(16.7		)	(15.1		)	(46.8		)	(34.9		)
EBITDA	42.3			106.0			432.1			724.4
Add:
FIFO impacts, (favorable) unfavorable	52.0			(54.3		)	6.2			(83.3		)
Share-based compensation	2.0			3.4			10.8			13.7
Major scheduled turnaround expenses	5.5			—			5.5			—
Gain on derivatives, net	(25.7		)	(72.5		)	(171.1		)	(173.0		)
Current period settlement on derivative contracts(a)	38.2			33.9			93.2			(3.9		)
Loss on extinguishment of debt	—			—			—			26.1
Adjustments included in noncontrolling interest	(23.8		)	25.9			15.2			45.7
Adjusted EBITDA	$	90.5		$	42.4		$	391.9		$	549.7


(a)	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.

Consolidated Results of Operations

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013 (Consolidated)

Net Sales. Consolidated net sales were $2,279.9 million for the three months ended September 30, 2014 compared to $1,977.1 million for the three months ended September 30, 2013. The increase of $302.8 million was primarily the result of an increase in petroleum net sales of $304.7 million due to higher overall sales volumes partially offset by lower sales prices for gasoline and distillates. The higher sales volumes in the petroleum business were primarily driven by the FCCU outage at the Coffeyville refinery during the three months ended September 30, 2013, partially offset by the Coffeyville refinery shutdown following the isomerization unit fire during the three months ended September 30, 2014. For the three months ended September 30, 2014, the petroleum segment’s average sales price per gallon of $2.69 for gasoline decreased by 6.9% while the petroleum segment's average sales price per gallon of $2.85 for distillate decreased 7.2%, as compared to the three months ended September 30, 2013. The nitrogen fertilizer segment net sales decreased $2.5 million primarily due to lower UAN sales prices and lower UAN volumes.

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Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $2,066.7 million for the three months ended September 30, 2014, as compared to $1,744.4 million for the three months ended September 30, 2013. The increase of $322.3 million primarily resulted from an increase in the cost of consumed crude oil and refined fuels purchased for resale at the petroleum segment. The increase in the cost of consumed crude oil was driven by an increase in consumed crude volumes, which was primarily the result of a reduction of crude throughputs due to the FCCU outage at the Coffeyville refinery during the three months ended September 30, 2013, partially offset by the Coffeyville refinery shutdown following the isomerization unit fire during the three months ended September 30, 2014. The nitrogen fertilizer segment cost of products sold (exclusive of depreciation and amortization) increased $2.4 million primarily due to increased railcar repairs and inspections and ammonia purchases.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $136.8 million for the three months ended September 30, 2014, as compared to $128.4 million for the three months ended September 30, 2013. The increase of $8.4 million was due primarily to an increase in the petroleum segment for expenses related to certain turnaround activities performed during the Coffeyville refinery shutdown, production chemicals, energy and utility costs and rental costs, partially offset by a decrease in repairs and maintenance. 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 energy and utility costs and refractory brick amortization.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $31.8 million for the three months ended September 30, 2014, as compared to $27.7 million for the three months ended September 30, 2013. The increase of $4.1 million was primarily the result of higher legal costs, partially offset by lower personnel costs, IT-related costs and consulting.

Operating Income. Consolidated operating income was $6.8 million for the three months ended September 30, 2014, as compared to operating income of $40.4 million for the three months ended September 30, 2013, a decrease of $33.6 million. The decrease in operating income was primarily the result of a decrease in the petroleum segment operating income of $19.5 million due to lower refining margins and higher direct operating expenses. Nitrogen fertilizer segment operating income decreased $6.9 million primarily as a result of lower net sales and higher cost of product sold and direct operating expenses.

Interest Expense. Consolidated interest expense for the three months ended September 30, 2014 was $9.4 million as compared to $11.7 million for the three months ended September 30, 2013. The decrease of $2.3 million resulted primarily from higher capitalized interest for the three months ended September 30, 2014.

Gain on Derivatives, net. For the three months ended September 30, 2014, the petroleum segment recorded a $25.7 million net gain on derivatives. This compares to a $72.5 million net gain on derivatives for the three months ended September 30, 2013. This change was primarily due to changes in crack spreads during the periods. The petroleum segment enters into over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production.

Income Tax Expense. Income tax expense for the three months ended September 30, 2014 was $4.2 million or 16.5% of income before income taxes, as compared to an income tax expense for the three months ended September 30, 2013 of $29.5 million or 27.4% of income before income taxes. The effective tax rate for the three months ended September 30, 2014 reflects the realization of additional domestic production activities deduction benefits of $1.7 million in the period. Additionally, our 2014 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, 2014 Compared to the Nine Months Ended September 30, 2013 (Consolidated)

Net Sales. Consolidated net sales were $7,267.7 million for the nine months ended September 30, 2014 compared to $6,549.8 million for the nine months ended September 30, 2013. The increase of $717.9 million was primarily the result of an increase in petroleum net sales of $734.3 million due to higher overall sales volumes partially offset by lower sales prices for gasoline and distillates. The petroleum segment’s average sales price per gallon for the nine months ended September 30, 2014 of $2.74 for gasoline and $2.94 for distillate decreased by 4.2% and 3.3%, respectively, as compared to the nine months ended September 30, 2013. The nitrogen fertilizer segment net sales decreased $15.1 million primarily due to lower UAN sales prices and ammonia sales volumes, partially offset by higher UAN sales volumes.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $6,332.6 million for the nine months ended September 30, 2014, as compared to $5,343.5 million for the nine months ended September 30, 2013. The increase of $989.1 million primarily resulted from an increase in the

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cost of consumed crude oil and refined fuels purchased for resale at the petroleum segment due to higher consumed volumes and crude oil prices. The nitrogen fertilizer segment cost of products sold (exclusive of depreciation and amortization) increased $17.4 million primarily due to increased ammonia purchases, railcar repairs and inspections.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $380.3 million for the nine months ended September 30, 2014, as compared to $345.2 million for the nine months ended September 30, 2013. The increase of $35.1 million was due primarily to an increase at the petroleum segment for expenses related to energy and utility costs and labor. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher energy and utility costs and refractory brick amortization.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $86.2 million for the nine months ended September 30, 2014, as compared to $85.0 million for the nine months ended September 30, 2013. The increase of $1.2 million was primarily the result of higher legal costs, partially offset by lower personnel costs, IT-related costs and consulting.

Operating Income. Consolidated operating income was $354.9 million for the nine months ended September 30, 2014, as compared to operating income of $670.7 million for the nine months ended September 30, 2013, a decrease of $315.8 million. The decrease in operating income was primarily the result of a decrease in the petroleum segment operating income of $267.7 million due to lower refining margins and higher direct operating expenses. Nitrogen fertilizer segment operating income decreased $38.9 million primarily as a result of lower net sales and higher cost of product sold.

Interest Expense. Consolidated interest expense for the nine months ended September 30, 2014 was $28.8 million as compared to $39.6 million for the nine months ended September 30, 2013. The decrease of $10.8 million resulted primarily from interest expense on the outstanding 2022 Notes (as defined below) for the nine months ended September 30, 2014 as compared to interest expense incurred during the nine months ended September 30, 2013 related to both the Second Lien Notes (prior to their extinguishment in the first quarter of 2013) and the 2022 Notes and higher capitalized interest for the nine months ended September 30, 2014.

Gain on Derivatives, net. For the nine months ended September 30, 2014, the petroleum segment recorded a $171.1 million net gain on derivatives. This compares to a $173.0 million net gain on derivatives for the nine months ended September 30, 2013. This change was primarily due to changes in crack spreads during the periods. The petroleum segment enters into over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production.

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, 2014 was $118.8 million or 23.9% of income before income taxes, as compared to an income tax expense for the nine months ended September 30, 2013 of $222.8 million or 28.4% of income before income taxes. Our 2014 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.

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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, 2014 and 2013:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Consolidated Petroleum Segment Summary Financial Results
Net sales	$	2,215.2	$	1,910.5	$	7,056.9	$	6,322.6
Cost of product sold(1)	2,053.7		1,734.7		6,289.6		5,317.0
Direct operating expenses(1)(2)	105.1		104.7		297.5		274.5
Major scheduled turnaround expenses	5.5		—		5.5		—
Depreciation and amortization	29.7		28.8		89.9		85.2
Gross profit(3)	$	21.2	$	42.3	$	374.4	$	645.9
Plus:
Direct operating expenses and major scheduled turnaround expenses(1)	110.6		104.7		303.0		274.5
Depreciation and amortization	29.7		28.8		89.9		85.2
Refining margin(4)	$	161.5	$	175.8	$	767.3	$	1,005.6
Operating income	$	3.9	$	23.4	$	320.4	$	588.1
Adjusted Petroleum EBITDA(5)	$	129.9	$	33.9	$	517.0	$	594.5



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Refining margin(4)	$	9.96	$	11.89	$	14.29	$	20.15
Gross profit(3)	$	1.31	$	2.86	$	6.97	$	12.94
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2)	$	6.82	$	7.08	$	5.64	$	5.50
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6)	$	6.52	$	6.92	$	5.32	$	5.29
Barrels sold (barrels per day)(6)	184,262		164,431		208,461		190,055

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
			%			%			%			%
Refining Throughput and Production Data (bpd)
Throughput:
Sweet	164,067		89.3	130,876		78.1	178,390		86.5	147,074		76.9
Medium	1,610		0.9	20,752		12.4	1,558		0.7	17,901		9.4
Heavy sour	10,690		5.8	9,072		5.4	16,732		8.1	17,805		9.3
Total crude oil throughput	176,367		96.0	160,700		95.9	196,680		95.3	182,780		95.6
All other feedstocks and blendstocks	7,447		4.0	6,863		4.1	9,655		4.7	8,444		4.4
Total throughput	183,814		100.0	167,563		100.0	206,335		100.0	191,224		100.0
Production:
Gasoline	88,633		48.1	74,990		45.2	100,630		48.5	89,390		46.8
Distillate	78,711		42.8	69,390		41.8	87,477		42.2	79,230		41.4
Other (excluding internally produced fuel)	16,791		9.1	21,666		13.0	19,361		9.3	22,579		11.8
Total refining production (excluding internally produced fuel)	184,135		100.0	166,046		100.0	207,468		100.0	191,199		100.0
Product price (dollars per gallon):
Gasoline	$	2.69		$	2.89		$	2.74		$	2.86
Distillate	$	2.85		$	3.07		$	2.94		$	3.04



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	97.25		$	105.81		$	99.62		$	98.20
Crude Oil Differentials:
WTI less WTS (light/medium sour)	8.78			0.30			7.19			2.14
WTI less WCS (heavy sour)	18.34			22.92			19.47			22.27
NYMEX Crack Spreads:
Gasoline	18.13			16.27			19.83			23.92
Heating Oil	21.56			22.13			23.41			27.46
NYMEX 2-1-1 Crack Spread	19.85			19.20			21.62			25.69
PADD II Group 3 Basis:
Gasoline	(3.82		)	(1.57		)	(5.24		)	(2.43		)
Ultra Low Sulfur Diesel	0.56			0.80			(0.36		)	1.66
PADD II Group 3 Product Crack:
Gasoline	14.32			14.70			14.58			21.49
Ultra Low Sulfur Diesel	22.11			22.93			23.05			29.12
PADD II Group 3 2-1-1	18.21			18.81			18.81			25.31


(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.

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(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 the petroleum business’ financial results. 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 at which 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’ financial results. Our calculation of refining margin may differ from similar calculations of other companies in the 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 the petroleum business’ 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, helps investors evaluate the petroleum segment’s ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance. Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
	(in millions)
Petroleum:
Petroleum operating income	$	3.9	$	23.4		$	320.4		$	588.1
FIFO impacts (favorable), unfavorable(a)	52.0		(54.3		)	6.2			(83.3		)
Share-based compensation, non-cash	0.6		2.1			1.9			8.3
Major scheduled turnaround expenses(b)	5.5		—			5.5			—
Current period settlements on derivative contracts(c)	38.2		33.9			93.2			(3.9		)
Depreciation and amortization	29.7		28.8			89.9			85.2
Other income (expense), net	—		—			(0.1		)	0.1
Adjusted Petroleum EBITDA	$	129.9	$	33.9		$	517.0		$	594.5

(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 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 certain major scheduled turnaround activities performed at the petroleum segment’s Coffeyville refinery during the third quarter of 2014.

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(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,
	2014			2013		2014		2013
	(in millions)
Coffeyville Refinery Financial Results
Net sales	$	1,383.5		$	992.2	$	4,541.3	$	3,833.9
Cost of product sold (exclusive of depreciation and amortization)	1,311.4			893.8		4,068.6		3,206.4
Direct operating expenses (exclusive of depreciation and amortization)	62.2			68.4		169.2		170.7
Major scheduled turnaround expenses	5.5			—		5.5		—
Depreciation and amortization	17.6			17.7		54.4		52.9
Gross profit (loss)	$	(13.2	)	$	12.3	$	243.6	$	403.9
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	67.7			68.4		174.7		170.7
Depreciation and amortization	17.6			17.7		54.4		52.9
Refining margin	$	72.1		$	98.4	$	472.7	$	627.5



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
	(dollars per barrel)
Coffeyville Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	8.11		$	13.48	$	14.76	$	21.56
Gross profit (loss)	$	(1.48	)	$	1.69	$	7.61	$	13.88
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	7.62		$	9.37	$	5.46	$	5.86
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	7.01		$	9.12	$	4.96	$	5.51
Barrels sold (barrels per day)	104,836			81,532		128,963		113,518

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
		%		%		%		%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	85,835	83.8	69,785	84.0	100,063	79.9	88,337	78.4
Medium	—	—	514	0.6	493	0.4	454	0.4
Heavy sour	10,690	10.4	9,072	10.9	16,732	13.4	17,805	15.8
Total crude oil throughput	96,525	94.2	79,371	95.5	117,288	93.7	106,596	94.6
All other feedstocks and blendstocks	5,882	5.8	3,711	4.5	7,880	6.3	6,067	5.4
Total throughput	102,407	100.0	83,082	100.0	125,168	100.0	112,663	100.0
Production:
Gasoline	50,397	48.2	35,493	42.4	61,629	48.1	52,507	45.8
Distillate	45,935	43.9	35,206	42.0	55,011	43.0	48,018	41.9
Other (excluding internally produced fuel)	8,304	7.9	13,050	15.6	11,352	8.9	14,003	12.3
Total refining production (excluding internally produced fuel)	104,636	100.0	83,749	100.0	127,992	100.0	114,528	100.0



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Wynnewood Refinery Financial Results
Net sales	$	830.7	$	917.2	$	2,512.3	$	2,485.4
Cost of product sold (exclusive of depreciation and amortization)	742.3		841.1		2,221.0		2,110.2
Direct operating expenses (exclusive of depreciation and amortization)	43.0		36.2		128.4		103.8
Major scheduled turnaround expenses	—		—		—		—
Depreciation and amortization	10.2		9.9		30.3		28.7
Gross Profit	$	35.2	$	30.0	$	132.6	$	242.7
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	43.0		36.2		128.4		103.8
Depreciation and amortization	10.2		9.9		30.3		28.7
Refining margin	$	88.4	$	76.1	$	291.3	$	375.2

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(dollars per barrel)
Wynnewood Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	12.03	$	10.17	$	13.44	$	18.04
Gross profit	$	4.79	$	4.00	$	6.12	$	11.66
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	5.86	$	4.85	$	5.92	$	4.99
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	5.89	$	4.75	$	5.92	$	4.97
Barrels sold (barrels per day)	79,426		82,899		79,498		76,537



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
		%		%		%		%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	78,232	96.1	61,091	72.3	78,327	96.5	58,737	74.8
Medium	1,610	2.0	20,238	24.0	1,065	1.3	17,447	22.2
Heavy sour	—	—	—	—	—	—	—	—
Total crude oil throughput	79,842	98.1	81,329	96.3	79,392	97.8	76,184	97.0
All other feedstocks and blendstocks	1,565	1.9	3,152	3.7	1,775	2.2	2,377	3.0
Total throughput	81,407	100.0	84,481	100.0	81,167	100.0	78,561	100.0
Production:
Gasoline	38,236	48.1	39,497	48.0	39,001	49.1	36,883	48.1
Distillate	32,776	41.2	34,184	41.5	32,466	40.8	31,212	40.7
Other (excluding internally produced fuel)	8,487	10.7	8,616	10.5	8,009	10.1	8,576	11.2
Total refining production (excluding internally produced fuel)	79,499	100.0	82,297	100.0	79,476	100.0	76,671	100.0

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013 (Petroleum Business)

Net Sales. Petroleum net sales were $2,215.2 million for the three months ended September 30, 2014 compared to $1,910.5 million for the three months ended September 30, 2013. The increase of $304.7 million was the result of higher overall sales volumes partially offset by lower sales prices for gasoline and distillates. Overall sales volumes increased 23.0% for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013. The increase in sales volume was primarily driven by the FCCU outage at the Coffeyville refinery during the three months ended September 30, 2013, which resulted in a reduction of crude oil throughput and production and was partially offset by the Coffeyville refinery shutdown following the isomerization unit fire during the three months ended September 30, 2014. For the three months ended September 30, 2014, the average sales price per gallon for gasoline of $2.69 decreased by approximately 6.9% as compared to the three months ended September 30, 2013, and the average sales price per gallon for distillates of $2.85 for the three months ended September 30, 2014 decreased by approximately 7.2% as compared to the three months ended September 30, 2013.

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	Three Months Ended September 30, 2014					Three Months Ended September 30, 2013					Total Variance			Price Variance			Volume Variance
	Volume(1)	$ per barrel		Sales $(2)		Volume(1)	$ per barrel		Sales $(2)		Volume(1)	Sales $(2)		Price Variance			Volume Variance
														(in millions)
Gasoline	9.6	$	112.77	$	1,079.4	7.7	$	121.55	$	935.3	1.9	$	144.1	$	(84.0	)	$	228.1
Distillate	8.3	$	119.77	$	1,001.8	6.5	$	128.98	$	840.5	1.8	$	161.3	$	(77.0	)	$	238.3


(1)	Barrels in millions


(2)	Sales dollars in millions

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 and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $2,053.7 million for the three months ended September 30, 2014 compared to $1,734.7 million for the three months ended September 30, 2013. The increase of $319.0 million was primarily the result of an increase in the cost of consumed crude oil and refined fuels purchased for resale. The increase in consumed crude oil cost was due to a 9.7% increase in consumed volumes, which was partially offset by lower crude oil prices. The increase in consumed crude volumes was primarily the result of a reduction of crude throughputs as a result of the FCCU outage at the Coffeyville refinery during the three months ended September 30, 2013, partially offset by the Coffeyville refinery shutdown following the isomerization unit fire during the three months ended September 30, 2014. The average cost per barrel of crude oil consumed for the three months ended September 30, 2014 was $97.44 compared to $104.48 for the comparable period of 2013, a decrease of approximately 6.7%. Sales volumes of refined fuels increased by approximately 23.0%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the three months ended September 30, 2014, the petroleum business had an unfavorable FIFO inventory impact of $52.0 million compared to a favorable FIFO inventory impact of $54.3 million for the comparable period of 2013.

Refining margin per barrel of crude oil throughput decreased from $11.89 for the three months ended September 30, 2013 to $9.96 for the three months ended September 30, 2014. Refining margin adjusted for FIFO impact was $13.16 per crude oil throughput barrel for the three months ended September 30, 2014, as compared to $8.21 per crude oil throughput barrel for the three months ended September 30, 2013. Gross profit per barrel decreased to $1.31 for the three months ended September 30, 2014 as compared to gross profit per barrel of $2.86 in the equivalent period in 2013. The decrease in refining margin and gross profit per barrel was due primarily to the decrease in the sales prices of gasoline and distillates.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum business include costs associated with the actual operations of the 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 and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $110.6 million for the three months ended September 30, 2014 compared to direct operating expenses of $104.7 million for the three months ended September 30, 2013. The increase of $5.9 million was primarily the result of the increase in expenses associated with certain turnaround activities performed during the Coffeyville refinery shutdown ($5.5 million), production chemicals ($2.7 million), energy and utility costs ($1.9 million), rental costs ($1.4 million) and outside services ($0.9 million), partially offset by a decrease in repair and maintenance ($7.0 million). The decrease in repairs and maintenance expense was largely due to costs incurred related to the FCCU outage at the Coffeyville refinery during the three months ended September 30, 2013, partially offset by costs incurred as a result of the Coffeyville refinery shutdown following the isomerization unit fire during the three months ended September 30, 2014. Direct operating expenses per barrel of crude oil throughput for the three months ended September 30, 2014 decreased to $6.82 per barrel as compared to $7.08 per barrel for the three months ended September 30, 2013. The decrease in the direct operating expenses per barrel of crude oil throughput is primarily a function of the higher crude oil throughput volumes.

Operating Income. Petroleum operating income was $3.9 million for the three months ended September 30, 2014 as compared to operating income of $23.4 million for the three months ended September 30, 2013. The decrease of $19.5 million was primarily the result of a decrease in the refining margin ($14.3 million) and increases in direct operating expenses ($5.9 million) and depreciation and amortization ($0.9 million), partially offset by a decrease in selling, general and administrative expenses ($1.6 million).

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Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013 (Petroleum Business)

Net Sales. Petroleum net sales were $7,056.9 million for the nine months ended September 30, 2014 compared to $6,322.6 million for the nine months ended September 30, 2013. The increase of $734.3 million was primarily the result of higher overall sales volumes partially offset by lower sales prices for gasoline and distillates. Overall sales volumes increased 14.8% in the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. For the nine months ended September 30, 2014, the average sales price per gallon for gasoline of $2.74 decreased by approximately 4.2% as compared to the nine months ended September 30, 2013, and the average sales price per gallon for distillates of $2.94 for the nine months ended September 30, 2014 decreased by approximately 3.3% as compared to the nine months ended September 30, 2013.



	Nine Months Ended September 30, 2014					Nine Months Ended September 30, 2013					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	29.8	$	115.10	$	3,433.5	26.5	$	120.11	$	3,182.8	3.3	$	250.7	$	(149.3	)	$	400.0
Distillate	26.4	$	123.60	$	3,271.3	21.8	$	127.83	$	2,790.4	4.6	$	480.9	$	(112.0	)	$	592.9


(1)	Barrels in millions


(2)	Sales dollars in millions

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 and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $6,289.6 million for the nine months ended September 30, 2014 compared to $5,317.0 million for the nine months ended September 30, 2013. The increase of $972.6 million was primarily the result of an increase in the cost of consumed crude oil and refined fuels purchased for resale. The increase in consumed crude oil costs was due to a 7.6% increase in consumed volumes and higher crude oil prices. The average cost per barrel of crude oil consumed for the nine months ended September 30, 2014 was $98.50 compared to $94.52 for the comparable period of 2013, an increase of approximately 4.2%. Sales volumes of refined fuels increased by approximately 14.8% during the same period. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of 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, 2014, the petroleum business had an unfavorable FIFO inventory impact of $6.2 million compared to a favorable FIFO inventory impact of $83.3 million for the comparable period of 2013.

Refining margin per barrel of crude oil throughput decreased from $20.15 for the nine months ended September 30, 2013 to $14.29 for the nine months ended September 30, 2014. Refining margin adjusted for FIFO impact was $14.40 per crude oil throughput barrel for the nine months ended September 30, 2014, as compared to $18.48 per crude oil throughput barrel for the nine months ended September 30, 2013. Gross profit per barrel decreased to $6.97 for the nine months ended September 30, 2014 as compared to gross profit per barrel of $12.94 in the equivalent period in 2013. The decrease in refining margin and gross profit per barrel was primarily due to the increase in the per barrel cost of consumed crude oil combined with the decrease in sales prices for gasoline and distillates. Consumed crude oil costs increased due to a 1.4% increase in WTI and a smaller discount to WTI for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum business include costs associated with the actual operations of the 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 and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $303.0 million for the nine months ended September 30, 2014 compared to direct operating expenses of $274.5 million for the nine months ended September 30, 2013. The increase of $28.5 million was primarily the result of the increase in expenses associated with energy and utility costs ($13.9 million), labor ($7.7 million), certain turnaround activities performed at the Coffeyville refinery ($5.5 million), production chemicals ($4.2 million), rental costs ($3.4 million), environmental costs ($1.4 million) and outside services ($1.3 million). The increase was partially offset by a decrease in repair and maintenance ($8.7 million). The increase in energy and utility costs was primarily due to a 31.7% increase in natural gas cost per unit and a 12.3% increase in consumption. The decrease in repairs and maintenance expense was largely due to costs incurred related to the FCCU outage at the Coffeyville refinery during the nine months ended September 30, 2013, partially offset by costs incurred as a result of

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the Coffeyville refinery shutdown following the isomerization unit fire during the nine months ended September 30, 2014. Direct operating expenses per barrel of crude oil throughput for the nine months ended September 30, 2014 increased to $5.64 per barrel as compared to $5.50 per barrel for the nine months ended September 30, 2013. The increase in the direct operating expenses per barrel of crude oil throughput is primarily a function of the higher overall expenses.

Operating Income. Petroleum operating income was $320.4 million for the nine months ended September 30, 2014 as compared to operating income of $588.1 million for the nine months ended September 30, 2013. The decrease of $267.7 million was primarily the result of a decrease in the refining margin ($238.3 million) and increases in direct operating expenses ($28.5 million) and depreciation and amortization ($4.7 million), partially offset by a decrease in selling, general and administrative expenses ($3.8 million).

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, 2014 and 2013:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Nitrogen Fertilizer Business Financial Results
Net sales	$	66.7	$	69.2	$	224.3	$	239.4
Cost of product sold(1)	15.4		13.0		56.6		39.2
Direct operating expenses(1)	26.1		23.7		77.2		70.7
Selling, general and administrative(1)	4.0		4.6		13.9		15.8
Depreciation and amortization	6.8		6.6		20.3		18.5
Operating income	$	14.4	$	21.3	$	56.3	$	95.2
Adjusted Nitrogen Fertilizer EBITDA(2)	$	21.1	$	28.2	$	76.8	$	116.1

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(3)	99.8			100.4			283.0			303.0
Ammonia (net available for sale)(3)(4)	11.8			3.4			23.9			36.3
UAN	223.5			239.3			704.1			660.6
Pet coke consumed (thousand tons)	117.6			116.0			359.7			360.2
Pet coke (cost per ton)	$	29		$	30		$	28		$	30
Sales (thousand tons)(5):
Ammonia	6.2			3.3			14.5			37.9
UAN	220.3			226.7			714.2			638.1
Product pricing at gate (dollars per ton)(5):
Ammonia	$	503		$	505		$	497		$	654
UAN	$	254		$	259		$	263		$	295
On-stream factor(6):
Gasification	94.6		%	91.2		%	95.8		%	94.1		%
Ammonia	92.0		%	90.1		%	90.7		%	92.6		%
UAN	89.2		%	89.5		%	90.7		%	89.6		%
Reconciliation of net sales (dollars in millions):
Sales net at gate	$	59.2		$	60.4		$	195.3		$	212.9
Freight in revenue	7.0			7.8			20.6			21.6
Hydrogen revenue	0.1			0.8			6.9			4.7
Other revenue	0.4			0.2			1.5			0.2
Total net sales	$	66.7		$	69.2		$	224.3		$	239.4



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Market Indicators
Natural gas NYMEX (dollars per MMBtu)	$	3.95	$	3.56	$	4.41	$	3.69
Ammonia — Southern Plains (dollars per ton)	570		498		524		611
UAN — Corn belt (dollars per ton)	297		302		321		352


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

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(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). The Nitrogen Fertilizer Partnership recorded share-based compensation, non-cash, in each of the periods presented below and its plant generally undergoes a major scheduled turnaround every two to three years. We present Adjusted Nitrogen Fertilizer EBITDA because we have found it helpful to consider an operating measure that excludes expenses, such as major scheduled turnaround expense, relating to transactions not reflective of the Nitrogen Fertilizer Partnership’s core operations. In addition, we believe that it is useful to exclude from Adjusted Nitrogen Fertilizer EBITDA share-based compensation, non-cash, although it is a recurring cost incurred in the ordinary course of business. We believe share-based compensation, non-cash, reflects a non-cash cost which may obscure, for a given period, trends in the underlying business, due to the timing and nature of the equity awards. We also present Adjusted Nitrogen Fertilizer EBITDA because it is the starting point for calculating 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 Nitrogen Fertilizer EBITDA enables investors and analysts to better understand the Nitrogen Fertilizer Partnership’s ability to make distributions to its common unitholders, helps investors and analysts evaluate its ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance by allowing investors to evaluate the same information used by management. 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 Nitrogen Fertilizer EBITDA for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
	(in millions)
Nitrogen Fertilizer:
Nitrogen fertilizer operating income	$	14.4		$	21.3	$	56.3	$	95.2
Share-based compensation, non-cash	(0.1		)	0.3		0.2		2.3
Depreciation and amortization	6.8			6.6		20.3		18.5
Other income, net	—			—		—		0.1
Adjusted Nitrogen Fertilizer EBITDA	$	21.1		$	28.2	$	76.8	$	116.1

(3)

Gross tons produced for ammonia represent total ammonia produced, including ammonia produced that was upgraded into UAN. As a result of the completion of the UAN expansion project in February 2013, the Nitrogen Fertilizer Partnership expects to upgrade substantially all of the ammonia it produces into UAN. Net tons available for sale represent ammonia available for sale that was not upgraded into UAN.


(4)	In addition to produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 4,000 and 1,000 tons of ammonia during the three months ended September 30, 2014 and 2013, respectively. The Nitrogen Fertilizer Partnership acquired approximately 30,000 and 5,000 tons of ammonia during the nine months ended September 30, 2014 and 2013, respectively.


(5)	Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons and 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 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 impact of the shutdown for installation of the waste heat boiler, PSA unit upgrade and the Linde air separation unit maintenance, the on-stream factors for the nine months ended September 30, 2014 would have been 97.8% for gasifier, 93.0% for ammonia and 93.0% for UAN. Excluding the impacts of the UAN expansion coming on-line, the planned downtime associated with the replacement of damaged catalyst, the unplanned Linde air separation unit outages and the unplanned

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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.

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $66.7 million for the three months ended September 30, 2014 compared to $69.2 million for the three months ended September 30, 2013. The decrease of $2.5 million was primarily the result of lower UAN sales prices ($1.8 million), lower UAN sales volumes ($1.8 million) and lower hydrogen sales volumes ($0.7 million), partially offset by higher ammonia sales volumes ($1.6 million). For the three months ended September 30, 2014, UAN and ammonia made up $62.9 million and $3.3 million of nitrogen fertilizer net sales, respectively. This compared to UAN and ammonia net sales of $66.5 million and $1.7 million, respectively, for the three months ended September 30, 2013. The following table demonstrates the impact of sales volumes and pricing for UAN, ammonia and hydrogen for the three months ended September 30, 2014 and September 30, 2013:



	Three Months Ended September 30, 2014					Three Months Ended September 30, 2013					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)
UAN	220,347	$	285	$	62.9	226,714	$	293	$	66.5	(6,367	)	$	(3.6	)	$	(1.8	)	$	(1.8	)
Ammonia	6,151	$	536	$	3.3	3,251	$	533	$	1.7	2,900		$	1.6		$	—		$	1.6
Hydrogen	17,388	$	8	$	0.1	99,260	$	8	$	0.8	(81,872	)	$	(0.7	)	$	—		$	(0.7	)

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

(2) Includes freight charges. Hydrogen is based on $ per MSCF.

(3) Sales dollars in millions

The decrease in UAN sales volume and increase in ammonia sales volume for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 was primarily attributable to lower UAN production volume and higher net ammonia available for sale that was not upgraded into UAN.

Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons. The nitrogen fertilizer business believes product pricing at gate is meaningful because it sells products both at its 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 product pricing at gate provides a measure that is consistently comparable period to period. Average product prices at gate for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 decreased 1.9% for UAN and 0.4% for ammonia, respectively.

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, freight and distribution expenses and purchased ammonia costs. Cost of product sold (exclusive of depreciation and amortization) for the three months ended September 30, 2014 was $15.4 million compared to $13.0 million for the three months ended September 30, 2013. The $2.4 million increase resulted from $2.7 million in higher costs from transactions with third parties, partially offset by lower costs from transactions with affiliates of $0.3 million. The higher third-party costs incurred during the three months ended September 30, 2014 were primarily the result of increased railcar repairs and inspections and ammonia purchases (approximately 4,000 tons for the three months ended September 30, 2014 and 1,000 tons in the three months ended September 30, 2013), partially offset by lower freight expense as a result of lower UAN sales volumes.

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, 2014 were $26.1 million as compared to $23.7 million for the three months ended September 30, 2013. The $2.4 million increase resulted primarily from higher utilities ($1.4 million), refractory brick amortization ($0.7 million) and property taxes ($0.3 million). The increased utility costs were largely due to higher electricity prices.

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Operating Income. Nitrogen fertilizer operating income was $14.4 million for the three months ended September 30, 2014, as compared to operating income of $21.3 million for the three months ended September 30, 2013. The decrease of $6.9 million for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013 was the result of the decrease in net sales ($2.5 million), increases in cost of product sold ($2.4 million), direct operating expenses ($2.4 million) and depreciation and amortization ($0.2 million), partially offset by a decrease in selling, general and administrative expenses ($0.6 million).

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $224.3 million for the nine months ended September 30, 2014 compared to $239.4 million for the nine months ended September 30, 2013. The decrease of $15.1 million was primarily the result of lower UAN sales prices ($25.5 million), lower ammonia sales volumes ($15.8 million) and lower ammonia sales prices ($2.2 million), partially offset by higher UAN sales volumes ($24.9 million) and higher hydrogen sales volumes ($2.1 million). For the nine months ended September 30, 2014, UAN and ammonia made up $208.4 million and $7.5 million of nitrogen fertilizer net sales, respectively. This compared to UAN and ammonia net sales of $209.0 million and $25.5 million, respectively, for the nine months ended September 30, 2013. The following table demonstrates the impact of sales volumes and pricing for UAN, ammonia and hydrogen for the nine months ended September 30, 2014 and September 30, 2013:



	Nine Months Ended September 30, 2014					Nine Months Ended September 30, 2013					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)
UAN	714,233	$	292	$	208.4	638,142	$	328	$	209.0	76,091		$	(0.6	)	$	(25.5	)	$	24.9
Ammonia	14,452	$	522	$	7.5	37,891	$	672	$	25.5	(23,439	)	$	(18.0	)	$	(2.2	)	$	(15.8	)
Hydrogen	688,819	$	10	$	6.9	477,075	$	10	$	4.7	211,744		$	2.2		$	0.1		$	2.1

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

(2) Includes freight charges. Hydrogen is based on $ per MSCF.

(3) Sales dollars in millions

The increase in UAN sales volume and decrease in ammonia sales volume for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 was partially attributable to the UAN expansion being available for the full period in 2014.

Product pricing at gate per ton represents net sales less freight revenue divided by product sales volume in tons. The nitrogen fertilizer business believes product pricing at gate is meaningful because it sells products both at its 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 product pricing at gate provides a measure that is consistently comparable period to period. Average product prices at gate for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased 10.8% for UAN and 24.0% for ammonia, respectively.

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, freight and distribution expenses and purchased ammonia costs. Cost of product sold (exclusive of depreciation and amortization) for the nine months ended September 30, 2014 was $56.6 million compared to $39.2 million for the nine months ended September 30, 2013. The $17.4 million increase resulted from $19.0 million in higher costs from transactions with third parties, partially offset by lower costs from transactions with affiliates of $1.6 million. The higher third-party costs incurred during the nine months ended September 30, 2014 were primarily the result of ammonia purchases (approximately 30,000 tons for the nine months ended September 30, 2014 and 5,000 tons for the nine months ended September 30, 2013) and increased railcar repairs and inspections.

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months ended September 30, 2013. The $6.5 million increase resulted primarily from higher utilities ($4.3 million), refractory brick amortization ($2.1 million) and catalyst amortization ($0.6 million), partially offset by lower insurance ($0.8 million). The increased utility costs were largely due to higher electrical volumes.

Operating Income. Nitrogen fertilizer operating income was $56.3 million for the nine months ended September 30, 2014, as compared to operating income of $95.2 million for the nine months ended September 30, 2013. The decrease of $38.9 million for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 was the result of a decrease in net sales ($15.1 million), increases in cost of products sold ($17.4 million), direct operating expenses ($6.5 million) and depreciation and amortization ($1.8 million), partially offset by a decrease in selling, general and administrative expenses ($1.9 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. With the exception of cash distributions paid to us by the Refining Partnership and Nitrogen Fertilizer Partnership, the cash needs of both the Refining Partnership and the Nitrogen Fertilizer Partnership have been met independently from the cash needs of CVR Energy and each other with a combination of existing cash and cash equivalent balances, cash generated from operating activities, credit facility borrowings and other debt. 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, 2014, we had consolidated cash and cash equivalents of $793.1 million. Of that amount, $365.9 million was cash and cash equivalents of CVR Energy, $359.2 million was cash and cash equivalents of the Refining Partnership and $68.0 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of October 28, 2014, we had consolidated cash and cash equivalents of approximately $829.6 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, 2014, the Refining Partnership had $372.7 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, 2014, the Nitrogen Fertilizer Partnership had $25.0 million available under the credit facility.

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, 2014, we currently hold approximately 66% and 53% of the Refining Partnership’s and the Nitrogen

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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, CVR Refining, LLC (“Refining LLC”) and its wholly-owned subsidiary, Coffeyville Finance Inc. (“Coffeyville Finance”), issued $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022 (the “2022 Notes”). As a result of the issuance, approximately $8.7 million of debt issuance costs were incurred, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of September 30, 2014, 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 2022 Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date.

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

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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, 2014, and the ratio was satisfied (not less than 2.5 to 1.0).

Amended and Restated Asset Based (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).

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

The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments 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, 2014.

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.

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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 currently based on 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 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, 2014, no amounts were drawn under the Nitrogen Fertilizer Partnership’s $25.0 million revolving credit facility.

Nitrogen Fertilizer Partnership Interest Rate Swaps

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 each of the three months ended September 30, 2014 and 2013 was $0.3 million in interest expense. For the three months ended September 30, 2014 and 2013, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0 and $0.3 million, respectively, which was unrealized in accumulated other comprehensive income. The impact recorded for each of the nine months ended September 30, 2014 and 2013 was $0.8 million, in interest expense. For each of the nine months ended September 30, 2014 and 2013, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0.1 million, which was unrealized in accumulated other comprehensive income.

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.

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The following table summarizes our total actual capital expenditures for the nine months ended September 30, 2014 by operating segment and major category:



	Nine Months Ended September 30, 2014
	(in millions)
Petroleum Business (the Refining Partnership):
Coffeyville refinery:
Maintenance	$	57.9
Growth	3.5
Coffeyville refinery total capital excluding turnaround expenditures	61.4
Wynnewood refinery:
Maintenance	49.1
Growth	32.4
Wynnewood refinery total capital excluding turnaround expenditures	81.5
Other Petroleum:
Maintenance	5.3
Growth	6.0
Other petroleum total capital excluding turnaround expenditures	11.3
Petroleum business total capital excluding turnaround expenditures	154.2
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
Maintenance	2.7
Growth	10.8
Nitrogen fertilizer business total capital excluding turnaround expenditures	13.5
Corporate	3.7
Total capital spending	$	171.4

Including amounts already spent during the nine months ended September 30, 2014, the Company expects to spend, in total, approximately $225.0 million to $250.0 million (excluding capitalized interest) on capital expenditures for the year ending December 31, 2014. This capital spending estimate includes approximately $4.0 million to $7.0 million associated with corporate related projects.

Petroleum Capital Spending

Including amounts already spent during the nine months ended September 30, 2014, the petroleum business expects to spend, in total, approximately $200.0 million to $220.0 million (excluding capitalized interest) on capital expenditures for the year ending December 31, 2014. Of this amount, $85.0 million to $95.0 million is expected to be spent for the Coffeyville refinery, which includes approximately $80.0 million to $85.0 million of maintenance capital. Approximately $95.0 million to $105.0 million is expected to be spent on capital expenditures for the Wynnewood refinery, which includes approximately $60.0 million to $65.0 million of maintenance capital. We also expect to spend $20.0 million on other petroleum capital projects.

In October 2014, the board of directors of the general partner of the Refining Partnership approved the construction of a hydrogen plant at the Coffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide additional hydrogen that is needed for environmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $122.5 million with an anticipated completion date in the second quarter of 2016.

Nitrogen Fertilizer Capital Spending

Including amounts already spent during the nine months ended September 30, 2014, the nitrogen fertilizer business expects to spend approximately $21.0 million to $23.0 million (excluding capitalized interest) on capital expenditures for the year ending December 31, 2014, which includes approximately $5.0 million to $6.0 million of maintenance capital expenditures. Growth capital expenditures in 2014 are inclusive of the upgrade to the PSA unit discussed in the following paragraph and the railcar purchases discussed in Note 14 ("Related Party Transactions") to Part I, Item I of this Report.

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During the second quarter of 2014, the gasification, ammonia and UAN units were taken down for between 5 to 7 days each to both install a waste heat boiler and upgrade the PSA unit. The upgraded PSA unit is projected to increase hydrogen recovery enough to allow the nitrogen fertilizer business to produce approximately 7,000 to 9,000 additional tons of ammonia fertilizer annually, at a total cost of approximately $4.7 million.

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 depending on market conditions, 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.

Cash Flows

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



	Nine Months Ended September 30,
	2014			2013
	(unaudited)
	(in millions)
Net cash provided by (used in):
Operating activities	$	530.8		$	321.3
Investing activities	(249.6		)	(177.4		)
Financing activities	(330.2		)	(152.8		)
Net decrease in cash and cash equivalents	$	(49.0	)	$	(8.9	)

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, 2014 were $530.8 million. The positive cash flow from operating activities generated over this period was primarily driven by $379.0 million of net income before noncontrolling interest, $77.5 million of favorable impacts to trade working capital and $54.7 million of favorable impacts to other working capital. Trade working capital for the nine months ended September 30, 2014 resulted in a net cash inflow of $77.5 million, which was attributable to an increase in accounts payable ($55.9 million) and decreases in accounts receivable ($11.8 million) and inventory ($9.8 million). The increase in accounts payable was largely the result of increased payables for crude purchases and timing of payments for the petroleum business. Other working capital activities resulted in a net cash inflow of $54.7 million, which was primarily related to increases in other current liabilities ($16.7 million), due to parent ($15.7 million) and accrued income taxes ($8.1 million) and a decrease in prepaid expenses and other current assets ($13.1 million). The increase in other current liabilities was primarily due to an increase in accruals related to the biofuel blending obligation at the petroleum business and increased accrued interest on the 2022 Notes due to the timing of payments. The increase in due to parent and accrued income taxes was the result of timing of tax payments to American Entertainment Properties Corporation ("AEPC") and other tax authorities. The decrease in prepaid expenses and other current assets was primarily due to the timing of payments for certain insurance policies and timing and overpayments related to the petroleum business' crude oil intermediation agreement.

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 was primarily driven by $562.6 million of net income before noncontrolling interest

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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). The increase in accounts receivable primarily resulted from increased sales volumes at the petroleum business as compared to the end of 2012 due to the turnaround at the Wynnewood refinery completed in the fourth quarter of 2012. The increase in inventory primarily resulted from increased gasoline and distillate prices, increased distillate volumes and increased crude oil prices as compared to 2012. The decrease in accounts payable primarily resulted from decreased payables at the petroleum business associated with the Wynnewood refinery turnaround, decreased capital accruals associated with the UAN expansion completed in February 2013 and decreased product accruals due to timing of payments, partially offset by increased payables for lease crude purchases due to increased crude gathering capacity and timing of payments. Other working capital activities resulted in a 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). The increase in due to parent is related to the timing of payments made to AEPC under the income tax allocation agreement. The increase in other current liabilities primarily resulted from an increase in the biofuel blending obligation at the petroleum business due to increased RINs prices in the third quarter of 2013.

Cash Flows Used in Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2014 was $249.6 million compared to $177.4 million for the nine months ended September 30, 2013. The increase in cash used in investing activities was the result of purchases of held available for-sale securities during the nine months ended September 30, 2014, partially offset by a $12.2 million decrease in capital spending. The decrease in capital spending was primarily the result of a decrease in nitrogen fertilizer capital expenditures of approximately $22.3 million, partially offset by an increase in the petroleum business capital expenditures of $13.4 million.

Cash Flows Used In Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2014 was approximately $330.2 million as compared to $152.8 million for the nine months ended September 30, 2013. The net cash used in financing activities for the nine months ended September 30, 2014 was primarily attributable to dividend payments to common stockholders of $369.0 million and distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $148.5 million, partially offset by proceeds of $188.3 million from the Refining Partnership's Second Underwritten Offering.

Net cash used in financing activities for the nine months ended September 30, 2013 was $152.8 million. 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 common units to AEPC of $61.5 million and proceeds from the Secondary Offering of CVR Partners' common units of $292.6 million.

For the three and nine months ended September 30, 2014, 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, 2014, there were no short-term borrowings outstanding under the Amended and Restated ABL credit facility.

Contractual Obligations

As of September 30, 2014, our contractual obligations included long-term debt, operating leases, capital lease obligations, unconditional purchase obligations, environmental liabilities and interest payments. There were no material changes outside the ordinary course of our business with respect to our contractual obligations during the nine months ended September 30, 2014 from those disclosed in our 2013 Form 10-K.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2014, as defined within the rules and regulations of the SEC.

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Recent Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“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. We adopted this standard prospectively as of January 1, 2014. The adoption of this standard resulted in a reclassification on the Condensed Consolidated Balance Sheets.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The standard is effective for interim and annual periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. We have not yet selected a transition method and are currently evaluating the standard and the impact on our consolidated financial statements and footnote disclosures.

Critical Accounting Policies

Our critical accounting policies are disclosed in the “Critical Accounting Policies” section of our 2013 Form 10-K. 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, 2014 does not differ materially from that discussed under Part II—Item 7A of our 2013 Form 10-K. 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, on 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, 2014, the Refining Partnership had open commodity hedging instruments consisting of 9.8 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at September 30, 2014 was a net unrealized gain of $61.8 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 $9.8 million.

Interest Rate Risk

The Nitrogen Fertilizer Partnership 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 facility, 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.

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The Nitrogen Fertilizer Partnership's credit facility is disclosed in Note 8 ("Long-Term Debt") and the Nitrogen Fertilizer Partnership's interest rate swap agreements are disclosed in Note 13 ("Derivative Financial Instruments") to Part I, Item I of this Report.

Foreign Currency Exchange

Given that our business is currently based entirely in the United States, we are not directly exposed to foreign currency exchange rate risk.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2014, we have evaluated, under the direction of our Chief Executive Officer and President and Chief Financial Officer and Treasurer, 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 President and Chief Financial Officer and Treasurer 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 President and our Chief Financial Officer and Treasurer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.

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, 2014 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 10 ("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 certain 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 2013 Form 10-K.

Item 6. Exhibits



Number		Exhibit Title
	31.1*	Rule 13a-14(a)/15(d)-14(a) Certification of Chief Executive Officer and President.
	31.2*	Rule 13a-14(a)/15(d)-14(a) Certification of Chief Financial Officer and Treasurer.
	32.1*	Section 1350 Certification of Chief Executive Officer and President.
	32.2*	Section 1350 Certification of Chief Financial Officer and Treasurer.
	101*	The following financial information for CVR Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, filed with the SEC on October 31, 2014, 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 (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.



October 31, 2014	By:	/s/ JOHN J. LIPINSKI
		Chief Executive Officer and President
		(Principal Executive Officer)

October 31, 2014	By:	/s/ SUSAN M. BALL
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer)