CVR ENERGY INC - Quarter Report: 2015 June (Form 10-Q)

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

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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 June 30, 2015

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 July 28, 2015.

CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended June 30, 2015



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

	Condensed Consolidated Balance Sheets - June 30, 2015 (unaudited) and December 31, 2014	6

	Condensed Consolidated Statements of Operations - Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	7

	Condensed Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	8

	Condensed Consolidated Statement of Changes in Equity - Six Months Ended June 30, 2015 (unaudited)	9

	Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2015 and 2014 (unaudited)	10

	Notes to the Condensed Consolidated Financial Statements - June 30, 2015 (unaudited)	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	68

Item 4.	Controls and Procedures	68

Part II. Other Information

Item 1.	Legal Proceedings	70

Item 1A.	Risk Factors	70

Item 6.	Exhibits	70

Signatures		71

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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 June 30, 2015 (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 barrel per 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 crude oil and other 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 throughputs 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 both 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 represents net sales less freight revenue divided by product sales volume in tons. Product pricing at gate is also referred to as netback.

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.

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).

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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



	June 30, 2015			December 31, 2014
	(unaudited)
	(in millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	937.7		$	753.7
Accounts receivable, net of allowance for doubtful accounts of $0.5 and $0.4	179.8			136.7
Inventories	349.5			329.6
Prepaid expenses and other current assets	86.2			174.7
Income tax receivable	4.3			11.1
Deferred income taxes	2.4			6.3
Due from parent	—			44.5
Total current assets	1,559.9			1,456.6
Property, plant and equipment, net of accumulated depreciation	1,916.5			1,916.0
Intangible assets, net	0.2			0.2
Goodwill	41.0			41.0
Deferred financing costs, net	7.2			8.4
Other long-term assets	22.8			40.3
Total assets	$	3,547.6		$	3,462.5
LIABILITIES AND EQUITY
Current liabilities:
Note payable and capital lease obligations	$	1.5		$	1.4
Current portion of long-term debt	125.0			—
Accounts payable	284.2			275.0
Personnel accruals	34.8			38.3
Accrued taxes other than income taxes	30.2			26.7
Due to parent	20.8			—
Deferred revenue	1.9			13.6
Other current liabilities	53.3			68.6
Total current liabilities	551.7			423.6
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion	547.7			673.5
Deferred income taxes	615.9			638.3
Other long-term liabilities	53.0			51.8
Total long-term liabilities	1,216.6			1,363.6
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			1,174.7
Retained deficit	(115.1		)	(184.9		)
Treasury stock, 98,610 shares at cost	(2.3		)	(2.3		)
Accumulated other comprehensive loss, net of tax	(0.2		)	(0.3		)
Total CVR stockholders' equity	1,058.0			988.1
Noncontrolling interest	721.3			687.2
Total equity	1,779.3			1,675.3
Total liabilities and equity	$	3,547.6		$	3,462.5

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(unaudited)
	(in millions, except per share data)
Net sales	$	1,624.2		$	2,540.3		$	3,013.1		$	4,987.8
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)	1,192.2			2,189.0			2,265.8			4,265.9
Direct operating expenses (exclusive of depreciation and amortization)	115.4			120.1			226.9			243.5
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Selling, general and administrative expenses (exclusive of depreciation and amortization)	27.2			28.0			52.4			54.4
Depreciation and amortization	42.5			38.6			84.5			75.9
Total operating costs and expenses	1,350.0			2,375.7			2,602.3			4,639.7
Operating income	274.2			164.6			410.8			348.1
Other income (expense):
Interest expense and other financing costs	(11.9		)	(9.3		)	(24.6		)	(19.4		)
Interest income	0.3			0.2			0.4			0.4
Gain (loss) on derivatives, net	(12.6		)	35.9			(64.0		)	145.3
Other income (expense), net	0.2			(2.2		)	36.3			(2.1		)
Total other income (expense)	(24.0		)	24.6			(51.9		)	124.2
Income before income taxes	250.2			189.2			358.9			472.3
Income tax expense	58.1			45.2			82.1			114.6
Net income	192.1			144.0			276.8			357.7
Less: Net income attributable to noncontrolling interest	90.2			60.3			120.1			147.3
Net income attributable to CVR Energy stockholders	$	101.9		$	83.7		$	156.7		$	210.4

Basic earnings per share	$	1.17		$	0.96		$	1.80		$	2.42
Diluted earnings per share	$	1.17		$	0.96		$	1.80		$	2.42
Dividends declared per share	$	0.50		$	0.75		$	1.00		$	1.50

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 June 30,					Six Months Ended June 30,
	2015		2014			2015			2014
	(unaudited)
	(in millions)
Net income	$	192.1	$	144.0		$	276.8		$	357.7
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $0, $0, $12.6 and $0	—		—			19.2			—
Net gain reclassified into income on sale of available-for-sale securities, net of tax of $0, $0, $(8.0) and $0 (Note 11)	—		—			(12.1		)	—
Net gain reclassified into income on reclassification of available-for-sale securities to trading securities, net of tax of $0, $0, $(4.6) and $0 (Note 11)	—		—			(7.1		)	—
Change in fair value of interest rate swap, net of tax of $0, $0, $0 and $(0.1)	—		(0.1		)	(0.1		)	(0.1		)
Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.1, $0.1, $0.1 and $0.1 (Note 12)	0.2		0.2			0.4			0.4
Total other comprehensive income	0.2		0.1			0.3			0.3
Comprehensive income	192.3		144.1			277.1			358.0
Less: Comprehensive income attributable to noncontrolling interest	90.4		60.4			120.3			147.5
Comprehensive income attributable to CVR Energy stockholders	$	101.9	$	83.7		$	156.8		$	210.5

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 Deficit			Treasury Stock			Accumulated Other Comprehensive Loss			Total CVR Stockholders' Equity			Noncontrolling Interest			Total Equity
	(unaudited)
	(in millions, except share data)
Balance at December 31, 2014	86,929,660	$	0.9	$	1,174.7	$	(184.9	)	$	(2.3	)	$	(0.3	)	$	988.1		$	687.2		$	1,675.3
Dividends paid to CVR Energy stockholders	—	—		—		(86.8		)	—			—			(86.8		)	—			(86.8		)
Distributions from CVR Partners to public unitholders	—	—		—		—			—			—			—			(29.4		)	(29.4		)
Distributions from CVR Refining to public unitholders	—	—		—		—			—			—			—			(56.8		)	(56.8		)
Share-based compensation	—	—		—		(0.1		)	—			—			(0.1		)	—			(0.1		)
Net income	—	—		—		156.7			—			—			156.7			120.1			276.8
Net gain on interest rate swaps, net of tax	—	—		—		—			—			0.1			0.1			0.2			0.3
Balance at June 30, 2015	86,929,660	$	0.9	$	1,174.7	$	(115.1	)	$	(2.3	)	$	(0.2	)	$	1,058.0		$	721.3		$	1,779.3

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six Months Ended June 30,
	2015			2014
	(unaudited)
	(in millions)
Cash flows from operating activities:
Net income	$	276.8		$	357.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	84.5			75.9
Allowance for doubtful accounts	0.1			(0.4		)
Amortization of deferred financing costs	1.4			1.4
Deferred income taxes	(17.6		)	(25.1		)
Loss on disposition of assets	1.4			0.4
Share-based compensation	5.9			8.9
Gain on sale of available-for-sale securities	(20.1		)	—
(Gain) loss on derivatives, net	64.0			(145.3		)
Current period settlements on derivative contracts	(34.8		)	55.0
Changes in assets and liabilities:
Accounts receivable	(43.7		)	(6.6		)
Inventories	(19.9		)	(2.1		)
Prepaid expenses and other current assets	34.2			6.3
Other long-term assets	(0.3		)	(0.9		)
Accounts payable	9.6			28.6
Accrued income taxes	6.8			11.0
Due to parent	65.3			27.9
Deferred revenue	(11.7		)	(0.3		)
Other current liabilities	(25.8		)	13.1
Other long-term liabilities	0.3			—
Net cash provided by operating activities	376.4			405.5
Cash flows from investing activities:
Capital expenditures	(86.7		)	(114.9		)
Proceeds from sale of assets	—			0.2
Purchase of available-for-sale securities	—			(78.3		)
Proceeds from sale of available-for-sale securities	68.0			—
Net cash used in investing activities	(18.7		)	(193.0		)
Cash flows from financing activities:
Payment of capital lease obligations	(0.7		)	(0.7		)
Proceeds from CVR Refining's June 2014 offering, net of offering costs	—			163.9
Dividends to CVR Energy's stockholders	(86.8		)	(130.2		)
Distributions to CVR Refining's noncontrolling interest holders	(56.8		)	(61.2		)
Distributions to CVR Partners' noncontrolling interest holders	(29.4		)	(27.7		)
Net cash used in financing activities	(173.7		)	(55.9		)
Net increase in cash and cash equivalents	184.0			156.6
Cash and cash equivalents, beginning of period	753.7			842.1
Cash and cash equivalents, end of period	$	937.7		$	998.7
Supplemental disclosures:
Cash paid for income taxes, net of refunds	$	27.7		$	100.7
Cash paid for interest net of capitalized interest of $1.2 and $5.2 in 2015 and 2014, respectively	$	23.1		$	17.9
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	$	21.3		$	23.5
Change in accounts payable related to construction in process additions	$	(0.3	)	$	(9.3	)

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

June 30, 2015

(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 and markets 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, an affiliate of Icahn Enterprises L.P. ("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 June 30, 2015, IEP and its affiliates owned approximately 82% of all outstanding shares.

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 whereby it sold 12,000,000 common units to the public (the "Secondary Offering").

Subsequent to the closing of the Secondary Offering and as of June 30, 2015, 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)

June 30, 2015

(unaudited)

CVR Refining, LP

On January 23, 2013, the Refining Partnership completed the initial public offering of its common units representing limited partner interests (the "Refining Partnership IPO"). The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." On May 20, 2013, the Refining Partnership completed an underwritten offering (the "Underwritten Offering") by selling additional common units to the public. In connection with the Underwritten Offering, American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased common units in a privately negotiated transaction with a subsidiary of CVR, which was completed on May 29, 2013. Following the closing of the Underwritten Offering and sale of common units to AEPC and prior to June 30, 2014, public security holders held approximately 29% of the total Refining Partnership common units (including units owned by affiliates of 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 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 through July 23, 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 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 in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of approximately $9.7 million.

Subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of June 30, 2015, public security holders held approximately 34% of the total Refining Partnership common units (including units owned by affiliates of 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 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

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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, 2014 audited consolidated financial statements and notes thereto included in CVR's Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC as of February 20, 2015 (the "2014 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 June 30, 2015 and December 31, 2014, the results of operations and comprehensive income for the three and six month periods ended June 30, 2015 and 2014, changes in equity for the six month period ended June 30, 2015 and cash flows of the Company for the six month periods ended June 30, 2015 and 2014.

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 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, 2015 or any other interim or annual period.

(2) Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("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. On July 9, 2015, the FASB approved a one-year deferral of the effective date making the standard effective for interim and annual periods beginning after December 15, 2017. The FASB will continue to permit entities to adopt the standard on the original

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effective date if they choose. 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.

In February 2015, the FASB issued ASU No. 2015-02, "Consolidations (Topic 810) - Amendments to the Consolidation Analysis." The new guidance makes amendments to the current consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and other similar entities. Under this analysis, limited partnerships and other similar entities will be considered a variable interest entity ("VIE") unless the limited partners hold substantive kick-out rights or participating rights. The standard is effective for interim and annual periods beginning after December 15, 2015. The Company is currently evaluating the standard and the impact, if any, on its consolidated financial statements and footnote disclosures.

In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"). The new standard requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The standard is effective for interim and annual periods beginning after December 31, 2015 and is required to be applied on a retrospective basis. Early adoption is permitted. The Company expects that the adoption of ASU 2015-03 will result in a reclassification of certain debt issuance costs on the Condensed Consolidated Balance Sheets.

(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 June 30, 2015, only restricted stock units under the LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. The LTIP authorized a share pool of 7,500,000 shares of the Company's common stock, 1,000,000 of which may be issued in respect of incentive stock options.

Restricted Stock Units

A summary of restricted stock units grant activity and changes during the six months ended June 30, 2015 is presented below:



	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2015	48,011		$	45.89
Granted	—		—
Vested	(3,630	)	32.44
Forfeited	(3,671	)	47.68
Non-vested at June 30, 2015	40,710		$	46.93

Through the LTIP, shares of restricted common stock were previously granted to employees of the Company. These restricted shares are generally graded-vesting awards, which vest over a three-year period. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. The IEP Acquisition and related Transaction Agreement dated April 18, 2012 between CVR and an affiliate of IEP (the "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 would 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 31 of each year. The awards are 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 2012 and 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. 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

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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, are remeasured at each subsequent reporting date until they vest.

As of June 30, 2015, there was approximately $0.4 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 June 30, 2015 and 2014 was approximately $(0.1) million and $0.9 million, respectively. Total compensation expense for the six months ended June 30, 2015 and 2014 was approximately $0.3 million and $1.5 million, respectively, related to the awards.

As of June 30, 2015 and December 31, 2014, the Company had a liability of $1.9 million and $1.7 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

Mr. Lipinski's performance unit awards were fully vested as of December 31, 2014 and paid as of March 31, 2015 with no remaining performance unit awards outstanding. Total compensation expense for the three and six months ended June 30, 2014 related to the performance awards was approximately $1.9 million and $3.6 million, respectively.

Long-Term Incentive Plan – CVR Partners

Phantom Units

CVR Partners has a long-term incentive plan ("CVR Partners LTIP") that 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. 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.

Through the CVR Partners LTIP, phantom 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 2013 and 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. These awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. 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 Nitrogen Fertilizer Partnership's common units in accordance with the award agreement, 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, are remeasured at each subsequent reporting date until they vest.

A summary of the phantom unit activity and changes under the CVR Partners LTIP during the six months ended June 30, 2015 is presented below:



	Phantom Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2015	243,946		$	11.07
Granted	—		—
Vested	—		—
Forfeited	(2,388	)	10.99
Non-vested at June 30, 2015	241,558		$	11.08

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As of June 30, 2015, there was approximately $2.1 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.4 years. Total compensation expense for the three months ended June 30, 2015 and 2014 related to the awards under the CVR Partners LTIP was approximately $0.4 million and $0.2 million, respectively. Total compensation expense recorded for the six months ended June 30, 2015 and 2014 related to the awards under the CVR Partners LTIP was approximately $1.0 million and $0.6 million, respectively.

As of June 30, 2015 and December 31, 2014, the Nitrogen Fertilizer Partnership had a liability of $1.2 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 the Chief Executive Officer and President of its general partner that included performance-based phantom units and distribution equivalent rights. Compensation cost is being recognized over the performance cycles of 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 in accordance with the award agreement, 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 six months ended June 30, 2015 and 2014 related to the award was not material. Based on current estimates of performance thresholds for the remaining performance cycles, unrecognized compensation expense and the liability associated with the unvested phantom units at June 30, 2015 were also not material.

Long-Term Incentive Plan – CVR Refining

CVR Refining has a long-term incentive plan ("CVR Refining LTIP") that 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. 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 for the benefit of the Refining Partnership.

In 2013 and 2014, 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 generally graded-vesting awards, which are expected to vest over three years with one-third of the awards vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. 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 in accordance with the award agreement, 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, are remeasured at each subsequent reporting date until they vest.

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A summary of phantom unit activity and changes under the CVR Refining LTIP during the six months ended June 30, 2015 is presented below:



	Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2015	403,947		$	18.89
Granted	—		—
Vested	—		—
Forfeited	(33,260	)	19.13
Non-vested at June 30, 2015	370,687		$	18.87

As of June 30, 2015, there was approximately $4.5 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.4 years. Total compensation expense recorded for the three months ended June 30, 2015 and 2014 related to the awards under the CVR Refining LTIP was approximately $0.6 million and $0.8 million, respectively. Total compensation expense recorded for the six months ended June 30, 2015 and 2014 related to the awards under the CVR Refining LTIP was approximately $2.0 million and $1.5 million, respectively.

As of June 30, 2015 and December 31, 2014, the Refining Partnership had a liability of $3.0 million and $1.0 million, respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

In December 2014, the Company granted an award of 227,927 incentive units in the form of stock appreciation rights ("SARs") to an executive of CVR Energy. In April 2015, the award granted was cancelled and replaced by an award of notional units in the form of SARs by CVR Refining pursuant to the CVR Refining LTIP. The replacement award is structured on the same economic and other terms as the incentive unit award and did not result in a material impact. Each SAR vests over three years and entitles the executive to receive a cash payment in an amount equal to the excess of the fair market value of one unit of the Refining Partnership's common units for the first ten trading days in the month prior to vesting over the grant price of the SAR. The fair value will be adjusted to include all distributions declared and paid by the Refining Partnership during the vesting period. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model. Assumptions utilized to value the award have been omitted due to immateriality of the award. Total compensation expense during the three and six months ended June 30, 2015 and the liability as of June 30, 2015 were not material.

Incentive Unit Awards

In 2013, 2014 and 2015, the Company granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energy and CVR GP, LLC. The awards are generally graded vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. 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 in accordance with the award agreement, 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, are remeasured at each subsequent reporting date until they vest.

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A summary of incentive unit activity and changes during the six months ended June 30, 2015 is presented below:



	Incentive Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2015	435,515		$	18.95
Granted	18,750		19.42
Vested	—		—
Forfeited	(13,649	)	19.72
Non-vested at June 30, 2015	440,616		$	18.95

As of June 30, 2015, there was approximately $5.6 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 approximately 1.4 years. Total compensation expense for the three months ended June 30, 2015 and 2014 related to the awards was approximately $0.9 million and $0.8 million, respectively. Total compensation expense for the six months ended June 30, 2015 and 2014 related to the awards was approximately $2.4 million and $1.6 million, respectively.

As of June 30, 2015 and December 31, 2014, the Company had a liability of $3.3 million and $0.8 million, respectively, 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:



	June 30, 2015		December 31, 2014
	(in millions)
Finished goods	$	158.2	$	176.2
Raw materials and precious metals	124.1		88.0
In-process inventories	18.5		20.6
Parts and supplies	48.7		44.8
	$	349.5	$	329.6

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(5) Property, Plant and Equipment

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



	June 30, 2015		December 31, 2014
	(in millions)
Land and improvements	$	37.8	$	37.4
Buildings	51.5		50.4
Machinery and equipment	2,617.2		2,581.2
Automotive equipment	23.4		22.1
Furniture and fixtures	19.9		19.0
Leasehold improvements	3.4		3.4
Aircraft	3.6		3.7
Railcars	14.9		14.5
Construction in progress	113.7		71.5
	2,885.4		2,803.2
Accumulated depreciation	968.9		887.2
Total property, plant and equipment, net	$	1,916.5	$	1,916.0

Capitalized interest recognized as interest expense for the three months ended June 30, 2015 and 2014 totaled approximately $0.8 million and $2.9 million, respectively. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2015 and 2014 totaled approximately $1.2 million and $5.2 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at both June 30, 2015 and December 31, 2014. 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 $1.8 million and $1.5 million for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, cost of product sold excludes depreciation and amortization of approximately $3.6 million and $3.0 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 $38.8 million and $35.6 million for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, direct operating expenses exclude depreciation and amortization of approximately $77.3 million and $70.0 million, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources, information technology and maintaining the corporate and administrative office in Texas and the administrative office in Kansas. Selling, general and administrative expenses exclude depreciation and amortization of approximately $1.9 million and $1.5 million for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, selling, general and administrative expense excludes depreciation and amortization of approximately $3.6 million and $2.9 million, respectively.

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(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 June 30, 2015, the Company's Condensed Consolidated Balance Sheet reflected a liability of $20.8 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three and six months ended June 30, 2015 and 2014, the Company paid $27.5 million and $98.1 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 June 30, 2015, the Company had unrecognized tax benefits of approximately $62.6 million, of which $30.1 million, if recognized, would impact the Company’s effective tax rate. Approximately $21.6 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. The Company has accrued interest of $8.5 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 June 30, 2015, 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, 2014 and in various individual states for the tax years ended December 31, 2010 through December 31, 2014.

The Company's effective tax rate for the three and six months ended June 30, 2015 was 23.2% and 22.9%, respectively, and the Company's effective tax rate for the three and six months ended June 30, 2014 was 23.9% and 24.3%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.6% for all periods. The Company's effective tax rate for the three and six months ended June 30, 2015 and 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.

(8) Long-Term Debt

Long-term debt was as follows:



	June 30, 2015			December 31, 2014
	(in millions)
6.5% Senior Notes due 2022	$	500.0		$	500.0
CRNF credit facility	125.0			125.0
Capital lease obligations	49.2			49.9
Total debt	674.2			674.9
Current portion of long-term debt and capital lease obligations	(126.5		)	(1.4		)
Long-term debt, net of current portion	$	547.7		$	673.5

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

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(unaudited)

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 June 30, 2015, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.

At June 30, 2015, the estimated fair value of the 2022 Notes was approximately $500.0 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.

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 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 June 30, 2015.

As of June 30, 2015, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $322.7 million and had letters of credit outstanding of approximately $27.8 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of June 30, 2015. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of June 30, 2015.

Nitrogen Fertilizer Partnership 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. No amounts were outstanding under the revolving credit facility at June 30, 2015. There is no scheduled amortization. The credit facility matures in April 2016; therefore, the principal portion of the term loan is presented as current portion of long-term debt on the Condensed Consolidated Balance Sheets as of June 30, 2015. The carrying value of the Nitrogen Fertilizer Partnership's debt approximates fair value. The Nitrogen Fertilizer Partnership is considering capital structure and refinancing options associated with the credit facility maturity.

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 incurrence of liens, disposal of assets, making restricted payments, making investments or acquisitions and entry 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 June 30, 2015, Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF") was in compliance with the covenants contained in the credit facility and there were no borrowings outstanding under the credit facility.

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(unaudited)

Capital Lease Obligations

The Refining Partnership maintains two leases, accounted for as a capital lease and a finance obligation, 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 172 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 171 months remaining and will expire in September 2029.

(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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions, except per share data)
Net income attributable to CVR Energy stockholders	$	101.9	$	83.7	$	156.7	$	210.4

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	$	1.17	$	0.96	$	1.80	$	2.42
Diluted earnings per share	$	1.17	$	0.96	$	1.80	$	2.42

There were no dilutive awards outstanding during the three and six months ended June 30, 2015 and 2014, 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)
Six Months Ending December 31, 2015	$	4.4	$	104.2
Year Ending December 31,
2016	7.9		126.7
2017	5.4		119.9
2018	3.8		116.7
2019	2.1		115.7
Thereafter	4.0		795.2
	$	27.6	$	1,378.4

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(unaudited)

(1)

This amount includes approximately $836.7 million payable ratably over sixteen 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"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of June 30, 2015, where applicable. 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 the three months ended June 30, 2015 and 2014, lease expense totaled approximately $2.1 million and $2.3 million, respectively. For the six months ended June 30, 2015 and 2014, lease expense totaled approximately $4.3 million and $4.5 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 June 30, 2015 and 2014, total expense of approximately $34.3 million and $34.6 million, respectively, was incurred related to long-term commitments. For the six months ended June 30, 2015 and 2014, total expense of approximately $66.5 million and $68.6 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 (as amended, 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 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 any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.

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 2014 Form 10-K and in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, which was filed with the SEC effective as of May 1, 2015 ("2015 Q1 Form 10-Q"). 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.

Flood, Crude Oil Discharge and Insurance

As previously disclosed in the 2014 Form 10-K and the 2015 Q1 Form 10-Q, CRRM filed a lawsuit against certain of its environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses at CRRM's Coffeyville refinery. During the second quarter of 2015, CRRM entered into a settlement agreement and release with the insurance carriers involved in the lawsuit, pursuant to which (i) CRRM received settlement proceeds of approximately $31.3 million, (ii) the parties mutually released each other from all claims relating to the flood and crude oil discharge and (iii) all pending appeals have been dismissed. Of the settlement proceeds received, $27.3 million were recorded as a flood insurance recovery in the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015. The remaining $4.0 million of settlement proceeds reduced CVR Refining's $4.0 million receivable related to this matter, which was included in other assets on the Condensed Consolidated Balance Sheets as of December 31, 2014.

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(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 either 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 the 2014 Form 10-K and the 2015 Q1 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.

As previously disclosed in the 2014 Form 10-K, in January 2014, the EPA issued an inspection report to WRC related to a RCRA compliance evaluation inspection conducted in March 2013 at the Wynnewood refinery. In February 2014, the Oklahoma Department of Environmental Quality ("ODEQ") notified WRC that it concurred with the EPA's inspection findings and would be pursuing enforcement. WRC and ODEQ entered into a Consent Order in June 2015 resolving all alleged non-compliance associated with the RCRA compliance evaluation inspection. The Consent Order requires WRC to take certain corrective actions, including specified groundwater remediation and monitoring measures pursuant to a work plan to be approved by ODEQ. CVR Refining does not anticipate that the costs of complying with the Consent Order will be material.

At June 30, 2015, the Company's Condensed Consolidated Balance Sheet included total environmental accruals of $3.0 million, compared with $1.1 million at December 31, 2014. Management periodically reviews and, as appropriate, revises its

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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 June 30, 2015 and 2014, capital expenditures were approximately $7.4 million and $26.4 million, respectively. For the six months ended June 30, 2015 and 2014, capital expenditures were approximately $18.3 million and $60.2 million, respectively. These expenditures were incurred for environmental compliance and efficiency of the operations.

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 June 30, 2015 and December 31, 2014. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be underfunded by approximately $500.4 million and $473.8 million as of June 30, 2015 and December 31, 2014, 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.

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(unaudited)

(11) 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 June 30, 2015 and December 31, 2014:



	June 30, 2015
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Cash equivalents	$	61.0	$	—		$	—	$	61.0
Other current assets (investments)	0.3		—			—		0.3
Other current assets (other derivative agreements)	—		14.4			—		14.4
Other long-term assets (other derivative agreements)	—		8.5			—		8.5
Total Assets	$	61.3	$	22.9		$	—	$	84.2
Other current liabilities (other derivative agreements)	—		(4.8		)	—		(4.8		)
Other current liabilities (interest rate swaps)	—		(0.6		)	—		(0.6		)
Other current liabilities (biofuel blending obligations)	—		(13.8		)	—		(13.8		)
Total Liabilities	$	—	$	(19.2	)	$	—	$	(19.2	)



	December 31, 2014
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Cash equivalents	$	69.0	$	—		$	—	$	69.0
Other current assets (investments)	73.9		2.7			—		76.6
Other current assets (other derivative agreements)	—		25.0			—		25.0
Other long-term assets (other derivative agreements)	—		22.3			—		22.3
Total Assets	$	142.9	$	50.0		$	—	$	192.9
Other current liabilities (interest rate swaps)	—		(0.8		)	—		(0.8		)
Other current liabilities (biofuel blending obligation)	—		(49.6		)	—		(49.6		)
Other long-term liabilities (interest rate swaps)	—		(0.2		)	—		(0.2		)
Total Liabilities	$	—	$	(50.6	)	$	—	$	(50.6	)

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(unaudited)

As of June 30, 2015 and December 31, 2014, 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 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 reported at fair market value using quoted market prices. During the six months ended June 30, 2015, the Company received proceeds of $68.0 million for the sale of a portion of its investment in available-for-sale securities. The aggregate cost basis for the available-for-sale securities sold was approximately $47.9 million. Upon the sale of the available-for-sale securities, the Company reclassified an unrealized gain of $20.1 million from accumulated other comprehensive income ("AOCI") and recognized a realized gain in other income in the Consolidated Statements of Operations for the six months ended June 30, 2015. At the end of the first quarter of 2015, the Company's remaining available-for-sale securities with an aggregate cost basis of approximately $25.7 million were reclassified to trading securities based on management's ability and intent with respect to the securities. In connection with the transfer to trading securities, an unrealized gain previously recorded in AOCI of $11.7 million was reclassified to other income and is reflected in the Condensed Consolidated Statements of Operations for the six months ended June 30, 2015. During the three months ended June 30, 2015, the trading securities were sold, and the Company received proceeds of $37.8 million and recognized an additional realized gain of $0.4 million in other income for the three and six months ended June 30, 2015. The Company had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2015.

(12) Derivative Financial Instruments

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(in millions)
Current period settlements on derivative contracts	$	(28.5	)	$	33.9	$	(34.8	)	$	55.0
Gain (loss) on derivatives, net	(12.6		)	35.9		(64.0		)	145.3

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. The fair value of the open commodity positions as of June 30, 2015 was a net loss of $1.5 million included in other current liabilities. For the three months ended

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(unaudited)

June 30, 2015 and 2014, the Refining Partnership recognized net losses of $0.4 million and $0.2 million, respectively. For the six months ended June 30, 2015 and 2014, the Refining Partnership recognized net losses of $1.4 million and $0.4 million, respectively. These recognized net losses are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

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 June 30, 2015 and December 31, 2014, the Refining Partnership had open commodity hedging instruments consisting of 8.1 million barrels and 9.1 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 June 30, 2015 was a net unrealized gain of $19.6 million, of which $14.4 million was included in current assets, $8.5 million was included in non-current assets and $3.3 million was included in current liabilities. For the three months ended June 30, 2015 and 2014, the Refining Partnership recognized a net loss of $12.2 million and a net gain of $36.1 million, respectively. For the six months ended June 30, 2015 and 2014, the Refining Partnership recognized a net loss of $62.6 million and a net gain of $145.7 million, respectively. These recognized net gains and losses are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

Nitrogen Fertilizer Partnership Interest Rate Swaps

CRNF has 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 agreements). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements 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 June 30, 2015, the effective rate of the term loan facility, net of impact of the interest rate swap agreements, was approximately 4.57%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of AOCI and will be reclassified into interest expense when the interest rate swap transaction affects earnings. Any 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-classified 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 June 30, 2015 and 2014, respectively. For the three months ended June 30, 2015 and 2014, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of approximately $0 and $0.1 million, respectively, which was 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 $0.5 million for each of the six months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0.1 million and $0.2 million, respectively, which was unrealized in AOCI.

Counterparty Credit Risk

The Refining Partnership's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The Refining Partnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

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 June 30, 2015, the counterparty credit risk adjustment was not material to the condensed consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.

Offsetting Assets and Liabilities

The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by the Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. The interest rate swap agreements held by the Nitrogen Fertilizer Partnership also provide for the right to setoff. However, as the interest rate swaps are in a liability position, there are no amounts offset in the Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014. 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 June 30, 2015 are recorded as current assets, non-current assets and current liabilities in prepaid expenses and other current assets, other long-term assets and other current liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:



	As of June 30, 2015
Description	Gross Current Assets		Gross Amounts Offset			Net Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	16.4	$	(2.0	)	$	14.4	$	—	$	14.4
Total	$	16.4	$	(2.0	)	$	14.4	$	—	$	14.4



	As of June 30, 2015
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	$	(0.1	)	$	8.5	$	—	$	8.5
Total	$	8.6	$	(0.1	)	$	8.5	$	—	$	8.5



	As of June 30, 2015
Description	Gross Current Liabilities		Gross Amounts Offset			Net Current Liabilities Presented		Cash Collateral Not Offset			Net Amount
	(in millions)
Commodity Swaps	$	7.8	$	(4.5	)	$	3.3	$	—		$	3.3
Other Derivative Activity	1.5		—			1.5		(1.5		)	—
Total	$	9.3	$	(4.5	)	$	4.8	$	(1.5	)	$	3.3

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 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 December 31, 2014
Description	Gross Current Assets		Gross Amounts Offset			Net Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	25.3	$	(0.3	)	$	25.0	$	—	$	25.0
Total	$	25.3	$	(0.3	)	$	25.0	$	—	$	25.0



	As of December 31, 2014
Description	Gross Non-Current Assets		Gross Amounts Offset		Net Non-Current Assets Presented		Cash Collateral Not Offset		Net Amount
	(in millions)
Commodity Swaps	$	22.3	$	—	$	22.3	$	—	$	22.3
Total	$	22.3	$	—	$	22.3	$	—	$	22.3

(13) 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 June 30, 2015, IEP and its affiliates owned approximately 82% of all common shares outstanding.

The following is a summary of dividends paid to the Company's stockholders, including IEP, for the respective quarters to which the distributions relate:



	December 31, 2014		March 31, 2015		Total Dividends Paid in 2015
	(in millions, except per share data)
Amount paid to IEP	$	35.6	$	35.6	$	71.2
Amounts paid to public stockholders	7.8		7.8		15.6
Total amount paid	$	43.4	$	43.4	$	86.8
Per common share	$	0.50	$	0.50	$	1.00
Shares outstanding	86.8		86.8

Tax Allocation Agreement

CVR is a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of IEP, and has entered into a Tax Allocation Agreement. Refer to Note 7 ("Income Taxes") for a discussion of related party transactions under the Tax Allocation Agreement.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

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 $0.1 million and $0, respectively, during the three months ended June 30, 2015 and 2014. The Company paid Insight Portfolio Group approximately $0.1 million during each of the six months ended June 30, 2015 and 2014. 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.

(14) 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. Intercompany net sales included in petroleum net sales were approximately $2.1 million and $2.3 million for the three months ended June 30, 2015 and 2014, respectively. Intercompany net sales included in petroleum net sales were approximately $4.2 million and $4.6 million for the six months ended June 30, 2015 and 2014, 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 $2.0 million and $0.9 million for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, the petroleum segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) of approximately $8.5 million and $6.8 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 June 30, 2015 and 2014, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $3.9 million and $4.5 million for the six months ended June 30, 2015 and 2014, 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, when applicable. For the three months ended June 30, 2015 and 2014, the net sales generated from intercompany hydrogen sales were approximately $2.0 million and $0.9 million, respectively. For the six months ended June 30, 2015 and 2014, the net sales generated from intercompany hydrogen sales were $8.5 million and $6.8 million, respectively. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

Other Segment

The other segment reflects intercompany eliminations, corporate cash and cash equivalents, income tax activities and other corporate activities that are not allocated to the operating segments.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Net sales
Petroleum	$	1,547.5		$	2,466.3		$	2,852.0		$	4,841.7
Nitrogen Fertilizer	80.8			77.2			173.9			157.5
Intersegment elimination	(4.1		)	(3.2		)	(12.8		)	(11.4		)
Total	$	1,624.2		$	2,540.3		$	3,013.1		$	4,987.8
Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,180.9		$	2,172.6		$	2,237.1		$	4,236.0
Nitrogen Fertilizer	15.4			19.4			41.2			41.1
Intersegment elimination	(4.1		)	(3.0		)	(12.5		)	(11.2		)
Total	$	1,192.2		$	2,189.0		$	2,265.8		$	4,265.9
Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	90.3		$	93.2		$	177.3		$	192.4
Nitrogen Fertilizer	25.1			26.9			49.6			51.1
Other	—			—			—			—
Total	$	115.4		$	120.1		$	226.9		$	243.5
Depreciation and amortization
Petroleum	$	34.2		$	30.7		$	68.2		$	60.2
Nitrogen Fertilizer	7.0			6.8			13.8			13.5
Other	1.3			1.1			2.5			2.2
Total	$	42.5		$	38.6		$	84.5		$	75.9
Operating income
Petroleum	$	250.8		$	151.9		$	360.0		$	316.5
Nitrogen Fertilizer	28.7			18.8			60.2			41.9
Other	(5.3		)	(6.1		)	(9.4		)	(10.3		)
Total	$	274.2		$	164.6		$	410.8		$	348.1
Capital expenditures
Petroleum	$	36.4		$	47.4		$	78.1		$	105.3
Nitrogen Fertilizer	3.4			4.1			6.0			7.5
Other	1.4			1.5			2.6			2.1
Total	$	41.2		$	53.0		$	86.7		$	114.9

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)



	As of June 30, 2015		As of December 31, 2014
	(in millions)
Total assets
Petroleum	$	2,516.3	$	2,417.8
Nitrogen Fertilizer	560.0		578.8
Other	471.3		465.9
Total	$	3,547.6	$	3,462.5
Goodwill
Petroleum	$	—	$	—
Nitrogen Fertilizer	41.0		41.0
Other	—		—
Total	$	41.0	$	41.0

(15) Subsequent Events

Dividend

On July 29, 2015, the board of directors of the Company declared a cash dividend for the second quarter of 2015 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on August 17, 2015 to stockholders of record at the close of business on August 10, 2015. IEP will receive $35.6 million in respect of its 82% ownership interest in the Company's shares.

Nitrogen Fertilizer Partnership Distribution

On July 29, 2015, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the second quarter of 2015 to the Nitrogen Fertilizer Partnership's unitholders of $0.39 per common unit, or $28.5 million in aggregate. The cash distribution will be paid on August 17, 2015 to unitholders of record at the close of business on August 10, 2015. The Company will receive $15.2 million in respect of its Nitrogen Fertilizer Partnership common units.

Refining Partnership Distribution

On July 29, 2015, the board of directors of the Refining Partnership's general partner declared a cash distribution for the second quarter of 2015 to the Refining Partnership's unitholders of $0.98 per common unit, or $144.6 million in aggregate. The cash distribution will be paid on August 17, 2015 to unitholders of record at the close of business on August 10, 2015. The Company will receive $95.4 million in respect of its Refining Partnership common units.

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

The following discussion and analysis 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, 2014 filed with the Securities and Exchange Commission ("SEC") as of February 20, 2015 (the "2014 Form 10-K"). Results of operations and cash flows for the three and six months ended June 30, 2015 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;


•	the risk of security breaches;


•	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 Report. We undertake no obligation to publicly update or revise 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 to the extent required by law.

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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 June 30, 2015, Icahn Enterprises L.P. ("IEP") and its affiliates 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 June 30, 2015, we owned the general partner and approximately 66% of the common units of the Refining Partnership. The petroleum business 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 complex crude oil 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 over 60,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, (2) a 170,000 bpd pipeline system (supported by approximately 336 miles of active Company owned and leased pipeline) that transports crude oil to the Coffeyville refinery from the Broome Station facility located near Caney, Kansas, (3) over 6.0 million barrels of owned and leased crude oil storage with an additional 0.5 million barrels expected to be added by the end of 2015, (4) 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 and (5) 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. 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 facility. The petroleum business maintains capacity on the Spearhead and Keystone pipelines from Canada to Cushing. The petroleum business began shipping on contracted capacity maintained on the Pony Express pipeline in May 2015. It also has contracted capacity on the White Cliffs pipeline, which is expected to be in-service by the end of 2015. Both the Pony Express and White Cliffs pipelines originate in Colorado and extend 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. Crude oil is supplied to the Wynnewood refinery through three third-party pipelines operated by Sunoco Pipeline, Excel Pipeline and Blueknight 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. In the fourth quarter of 2014, the petroleum business completed a hydrocracker project that increased the conversion capability and the ULSD yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of the refineries allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the second quarter of 2015 was $3.35 per barrel compared to a discount of $1.16 per barrel in the second quarter of 2014.

Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At June 30, 2015, 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. With the completion of the UAN expansion in February 2013, the nitrogen fertilizer business now upgrades substantially all of the ammonia it produces to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate which has historically commanded a premium price over ammonia. For the three and six months ended June 30, 2015, the nitrogen fertilizer business produced 253,500 and 505,600 tons of UAN and 107,100 and 203,000 tons of ammonia, respectively. For the three and six months ended June 30, 2015, approximately 96% and 97% of the produced ammonia tons and the majority of purchased ammonia tons were upgraded into UAN, respectively.

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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 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 Second Underwritten Offering

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 utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings, LLC ("CVR Refining Holdings"). Subsequent to the closing of the Second Underwritten Offering and through July 23, 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.

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 Renewable Fuel Standard ("RFS") of the United States Environmental Protection Agency (the "EPA"), which requires it to either blend "renewable fuels" in with its transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"), in lieu of blending.

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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. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was subject to the RFS for the first time.

On June 10, 2015, the EPA published the proposed annual percentage standards for 2014, 2015 and 2016 under the RFS program. For each year, the proposed volumes for cellulosic, advanced biofuel and renewable fuel are lower than the statutorily mandated volumes. However, the proposed volumes for biomass-based diesel are above the statutorily mandated volumes. The EPA is proposing to set the volume requirements for 2014 at the levels that were actually used in 2014. For 2015 and 2016, the EPA is proposing to increase the volume requirements above 2014 levels. In the same proposed rule, the EPA also published the proposed annual biomass-based diesel volume requirement for 2017. The EPA expects to finalize the proposed volumes by November 30, 2015.

The cost of RINs for the three months ended June 30, 2015 and 2014 was approximately $37.5 million and $29.1 million, respectively. The cost of RINs for the six months ended June 30, 2015 and 2014 was approximately $74.1 million and $63.8 million, respectively. The current and future cost of RINs for the petroleum business will be more accurately defined by the November 30, 2015 ruling. The future cost of RINs for the petroleum business is difficult to estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, 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 and downstream terminals, 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 currently estimates that the total cost of RINs will be approximately $110.0 million to $150.0 million for the year ending December 31, 2015.

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.

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

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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 petroleum business is significantly affected by developments in the markets in which it operates. For example, numerous pipeline projects in 2014 and 2015 expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and could see a downward movement in refining margins as a result.

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 six months ended June 30, 2015, a $1.00 change in natural gas prices would have increased or decreased the petroleum business' natural gas costs by approximately $6.1 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 the petroleum business' financial results.

Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results of operations. Unplanned downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The Coffeyville refinery completed the first phase of its last turnaround during the fourth quarter of 2011, with the second phase completed during the first quarter of 2012. The first phase of its next turnaround is scheduled to begin at the end of September 2015 and is expected to last approximately six to seven weeks at a total estimated cost of approximately $80.0 million to $85.0 million. The second phase is scheduled to begin in early 2016 at a total estimated cost of approximately $30.0 million to $35.0 million. The Wynnewood Refinery completed a turnaround in December 2012, and the next turnaround is scheduled to occur in the spring of 2017.

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, 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. 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 represents net sales less freight revenue divided by product sales volume in tons. The nitrogen fertilizer business believes product pricing at gate is a meaningful measure because it sells products at its plant gate and terminal locations' gates ("sold gate") and delivered to the customer's designated delivery site ("sold delivered"). The relative percentage of sold gate versus sold delivered can change period to period. The product pricing at gate provides a measure that is consistently comparable period to period.

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 2014, approximately 49% of the corn planted in the United States was grown within an estimated $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; however, it does incur costs to maintain and repair its railcar fleet. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

The nitrogen fertilizer business' largest raw material expense used in the production of ammonia is pet coke, which it purchases from the petroleum business and third parties. For the three months ended June 30, 2015 and 2014, the nitrogen fertilizer business incurred approximately $3.1 million and $3.2 million, respectively, for the cost of pet coke, which equaled an average cost per ton of $25 and $27. For the six months ended June 30, 2015 and 2014, the nitrogen fertilizer business incurred approximately $6.7 million and $6.8 million, respectively, for the cost of pet coke, which equaled an average cost per ton of $27 and $28.

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. Turnarounds are expected to last 14-21 days. 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. The Nitrogen Fertilizer Partnership is planning to undergo the next full facility turnaround in the third quarter of 2015, and the nitrogen fertilizer business currently anticipates the cost will be approximately $7.0 million.

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 and us and our subsidiaries (including the Refining Partnership). In connection with the Nitrogen Fertilizer Partnership IPO, certain of the intercompany agreements were amended and restated, and the nitrogen fertilizer business and the refining business entered into several new agreements. In connection with the Refining Partnership IPO, some of our subsidiaries party to these agreements became subsidiaries of the Refining Partnership.

These intercompany agreements include (i) the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operates the nitrogen fertilizer business; (iii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iv) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v) an easement agreement; (vi) an environmental agreement; and (vii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to the Nitrogen Fertilizer Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

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In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $250.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business.

Crude Oil Supply Agreement

On August 31, 2012, CRRM and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended, 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 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 any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Share-based compensation (a)	$	1.9		$	4.7		$	5.9		$	8.9
(Gain) loss on derivatives, net	12.6			(35.9		)	64.0			(145.3		)
Major scheduled turnaround expenses (b)	2.1			—			2.1			—
Flood insurance recovery (c)	(27.3		)	—			(27.3		)	—

_______________________________________


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


(b)	Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery ($1.7 million during the three and six months ended June 30, 2015) and the nitrogen fertilizer plant ($0.4 million during the three and six months ended June 30, 2015).


(c)	Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery on June/July 2007. Refer to Part I, Item 1, Note 10 ("Commitments and Contingencies") for further details.

Noncontrolling Interest

As a result of the Refining Partnership's closing of the Underwritten Offering in the second quarter of 2013, the noncontrolling interest reflected in our condensed consolidated financial statements was approximately 29% prior to June 30, 2014. Upon completion of the Second Underwritten Offering on June 30, 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 was approximately 34% as of and for the three and six months ended June 30, 2015. Additionally, as of and for the three and six months ended June 30, 2015 and 2014, the noncontrolling interest in the Nitrogen Fertilizer Partnership reflected in our condensed consolidated financial statements was approximately 47% for each period.

The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets is impacted by the noncontrolling ownership percentage of net income and related distributions for each reporting period for the Refining Partnership and the Nitrogen Fertilizer Partnership. 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

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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 cash interest expense (excluding capitalized interest) and debt service and other contractual obligations, maintenance capital expenditures and, to the extent applicable, major scheduled turnaround expenses 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 distribution may be increased by the release of 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 2015 for the respective quarters to which the distributions relate:



	December 31, 2014		March 31, 2015		Total Cash Distributions Paid in 2015
	($ in millions, expect per common unit data)
Amount paid to CRLLC	$	16.0	$	17.5	$	33.5
Amounts paid to public unitholders	14.0		15.4		29.4
Total amount paid	$	30.0	$	32.9	$	62.9
Per common unit	$	0.41	$	0.45	$	0.86
Common units outstanding	73.1		73.1

On July 29, 2015, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the second quarter of 2015 to the Nitrogen Fertilizer Partnership's unitholders of $0.39 per common unit or $28.5 million in aggregate. The cash distribution will be paid on August 17, 2015 to unitholders of record at the close of business on August 10, 2015. We will receive $15.2 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 distribution may be increased by the release of 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 2015 for the respective quarters to which the distributions relate:



	December 31, 2014		March 31, 2015		Total Cash Distributions Paid in 2015
	($ in millions, expect per common unit data)
Amount paid to CVR Refining Holdings, LLC	$	36.0	$	74.0	$	109.9
Amounts paid to public unitholders	18.6		38.2		56.8
Total amount paid	$	54.6	$	112.2	$	166.7
Per common unit	$	0.37	$	0.76	$	1.13
Common units outstanding	147.6		147.6

On July 29, 2015, the board of directors of the Refining Partnership's general partner declared a cash distribution for the second quarter of 2015 to the Refining Partnership's unitholders of $0.98 per common unit or $144.6 million in aggregate. The cash distribution will be paid on August 17, 2015 to unitholders of record at the close of business on August 10, 2015. We will receive $95.4 million in respect of our common units.

CVR Energy Dividends

On January 24, 2013, our board of directors adopted a quarterly cash dividend policy. Dividends are subject to change at the discretion of the board of directors and may change from quarter to quarter. We began paying regular quarterly dividends in the second quarter of 2013. Refer to Part I, Item 1, Note 13 ("Related Party Transactions") for a summary of dividends paid to the Company's stockholders, including IEP, during 2015.

On July 29, 2015, our board of directors declared a dividend for the second quarter of 2015 of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on August 17, 2015 to stockholders of record at the close of business on August 10, 2015.

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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 six months ended June 30, 2015 and 2014. 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, 2014, is unaudited.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions, except per share data)
Consolidated Statement of Operations Data
Net sales	$	1,624.2		$	2,540.3		$	3,013.1		$	4,987.8
Cost of product sold(1)	1,192.2			2,189.0			2,265.8			4,265.9
Direct operating expenses(1)	115.4			120.1			226.9			243.5
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Selling, general and administrative expenses(1)	27.2			28.0			52.4			54.4
Depreciation and amortization	42.5			38.6			84.5			75.9
Operating income	274.2			164.6			410.8			348.1
Interest expense and other financing costs	(11.9		)	(9.3		)	(24.6		)	(19.4		)
Interest income	0.3			0.2			0.4			0.4
Gain (loss) on derivatives, net	(12.6		)	35.9			(64.0		)	145.3
Other income (expense), net	0.2			(2.2		)	36.3			(2.1		)
Income before income tax expense	250.2			189.2			358.9			472.3
Income tax expense	58.1			45.2			82.1			114.6
Net income	192.1			144.0			276.8			357.7
Less: Net income attributable to noncontrolling interest	90.2			60.3			120.1			147.3
Net income attributable to CVR Energy stockholders	$	101.9		$	83.7		$	156.7		$	210.4

Basic earnings per share	$	1.17		$	0.96		$	1.80		$	2.42
Diluted earnings per share	$	1.17		$	0.96		$	1.80		$	2.42
Dividends declared per share	$	0.50		$	0.75		$	1.00		$	1.50
Adjusted EBITDA(2)	$	145.7		$	147.2		$	309.4		$	301.4

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 June 30, 2015		As of December 31, 2014
			(audited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	937.7	$	753.7
Working capital	1,008.2		1,033.0
Total assets	3,547.6		3,462.5
Total debt, including current portion	674.2		674.9
Total CVR Energy stockholders' equity	1,058.0		988.1

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	198.2		$	124.2		$	376.4		$	405.5
Investing activities	(15.3		)	(131.1		)	(18.7		)	(193.0		)
Financing activities	(97.4		)	43.5			(173.7		)	(55.9		)
Net cash flow	$	85.5		$	36.6		$	184.0		$	156.6

Capital expenditures for property, plant and equipment	$	41.2		$	53.0		$	86.7		$	114.9


(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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Depreciation and amortization excluded from cost of product sold	$	1.8	$	1.5	$	3.6	$	3.0
Depreciation and amortization excluded from direct operating expenses	38.8		35.6		77.3		70.0
Depreciation and amortization excluded from selling, general and administrative expenses	1.9		1.5		3.6		2.9
Total depreciation and amortization	$	42.5	$	38.6	$	84.5	$	75.9

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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 (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery. 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 six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Net income attributable to CVR Energy stockholders	$	101.9		$	83.7		$	156.7		$	210.4
Add:
Interest expense and other financing costs, net of interest income	11.6			9.1			24.2			19.0
Income tax expense	58.1			45.2			82.1			114.6
Depreciation and amortization	42.5			38.6			84.5			75.9
EBITDA adjustments included in noncontrolling interest	(19.2		)	(15.1		)	(38.7		)	(30.2		)
EBITDA	194.9			161.5			308.8			389.7
Add:
FIFO impacts, (favorable) unfavorable	(36.4		)	(24.3		)	(11.9		)	(45.9		)
Share-based compensation	1.9			4.7			5.9			8.9
Major scheduled turnaround expenses	2.1			—			2.1			—
(Gain) loss on derivatives, net	12.6			(35.9		)	64.0			(145.3		)
Current period settlement on derivative contracts(a)	(28.5		)	33.9			(34.8		)	55.0
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Adjustments included in noncontrolling interest	26.4			7.3			2.6			39.0
Adjusted EBITDA	$	145.7		$	147.2		$	309.4		$	301.4


(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 June 30, 2015 Compared to the Three Months Ended June 30, 2014 (Consolidated)

Net Sales. Consolidated net sales were $1,624.2 million for the three months ended June 30, 2015 compared to $2,540.3 million for the three months ended June 30, 2014. The decrease of $916.1 million was largely the result of a decrease in the petroleum segment's net sales of $918.8 million due to significantly lower sales prices. The petroleum segment's average sales price per gallon for the three months ended June 30, 2015 of $1.87 for gasoline and $1.81 for distillates decreased by 34.8% and 39.1%, respectively, as compared to the three months ended June 30, 2014. The nitrogen fertilizer segment net sales increased $3.6 million primarily due to higher UAN and ammonia sales volumes, partially offset by lower UAN sales prices.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $1,192.2 million for the three months ended June 30, 2015, as compared to $2,189.0 million for the three months ended June 30, 2014. The decrease of $996.8 million primarily resulted from a decrease of $991.7 million in cost of product sold at the petroleum segment. The decrease at the petroleum segment was due to decreases in the cost of consumed crude oil and purchased products for resale. The decrease in consumed crude oil costs was due to a 43.7% decrease in

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crude oil prices. The nitrogen fertilizer segment's cost of product sold (exclusive of depreciation and amortization) decreased $4.0 million primarily due to lower distribution costs and ammonia purchases.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $115.4 million for the three months ended June 30, 2015, as compared to $120.1 million for the three months ended June 30, 2014. The decrease of $4.7 million was primarily due to a decrease at the petroleum segment for expenses related to energy and utility costs. The nitrogen fertilizer segment's direct operating expenses (exclusive of depreciation and amortization) decreased primarily due to lower outside services and refractory brick amortization costs.

Flood Insurance Recovery. During the three months ended June 30, 2015, the petroleum segment received settlement proceeds from its environmental insurance carriers related to the June/July 2007 flood and crude oil discharge losses at CRRM’s Coffeyville refinery, of which $27.3 million was recorded as a flood insurance recovery. Refer to Part I, Item 1, Note 10 ("Commitments and Contingencies") for further details.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) of $27.2 million for the three months ended June 30, 2015 and $28.0 million for the three months ended June 30, 2014 remained relatively consistent over the comparable periods.

Operating Income. Consolidated operating income was $274.2 million for the three months ended June 30, 2015, as compared to operating income of $164.6 million for the three months ended June 30, 2014, an increase of $109.6 million. The increase in operating income was primarily the result of an increase in the petroleum segment's operating income of $98.9 million due to higher refining margin and the flood insurance recovery. Nitrogen fertilizer segment operating income increased $9.9 million primarily as a result of higher net sales and lower cost of product sold and direct operating expenses.

Interest Expense. Consolidated interest expense for the three months ended June 30, 2015 was $11.9 million, as compared to $9.3 million for the three months ended June 30, 2014. The increase of $2.6 million primarily resulted from lower capitalized interest for the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

Gain (Loss) on Derivatives, net. For the three months ended June 30, 2015, the petroleum segment recorded a $12.6 million net loss on derivatives. This compares to a $35.9 million net gain on derivatives for the three months ended June 30, 2014. 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 June 30, 2015 was $58.1 million or 23.2% of income before income taxes, as compared to income tax expense for the three months ended June 30, 2014 of $45.2 million or 23.9% of income before income taxes. Our 2015 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.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014 (Consolidated)

Net Sales. Consolidated net sales were $3,013.1 million for the six months ended June 30, 2015 compared to $4,987.8 million for the six months ended June 30, 2014. The decrease of $1,974.7 million was largely the result of a decrease in the petroleum segment's net sales of $1,989.7 million due to significantly lower sales prices. The petroleum segment's average sales price per gallon for the six months ended June 30, 2015 of $1.67 for gasoline and $1.75 for distillates decreased by 39.7% and 41.3%, respectively, as compared to the six months ended June 30, 2014. The nitrogen fertilizer segment net sales increased $16.4 million primarily due to higher UAN and ammonia sales volumes.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $2,265.8 million for the six months ended June 30, 2015, as compared to $4,265.9 million for the six months ended June 30, 2014. The decrease of $2,000.1 million primarily resulted from a decrease of $1,998.9 million in cost of product sold at the petroleum segment. The decrease at the petroleum segment was due to decreases in the cost of consumed crude oil and purchased products for resale. The decrease in consumed crude oil costs was due to a 47.1% decrease in crude oil prices. The nitrogen fertilizer segment's cost of product sold (exclusive of depreciation and amortization) remained relatively consistent over the comparable periods.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $226.9 million for the six months ended June 30, 2015, as compared to $243.5 million for the six months ended June 30, 2014. The decrease of $16.6 million was primarily due to a decrease at the petroleum

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segment for expenses related to energy and utility costs and repairs and maintenance. The nitrogen fertilizer segment's direct operating expenses (exclusive of depreciation and amortization) decreased due to lower outside services, utilities and refractory brick amortization costs.

Flood Insurance Recovery. During the six months ended June 30, 2015, the petroleum segment received settlement proceeds from its environmental insurance carriers related to the June/July 2007 flood and crude oil discharge losses at CRRM’s Coffeyville refinery, of which $27.3 million was recorded as a flood insurance recovery. Refer to Part I, Item 1, Note 10 ("Commitments and Contingencies") for further details.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $52.4 million for the six months ended June 30, 2015, as compared to $54.4 million for the six months ended June 30, 2014. The decrease of $2.0 million was primarily the result of lower share-based compensation and consulting costs.

Operating Income. Consolidated operating income was $410.8 million for the six months ended June 30, 2015, as compared to operating income of $348.1 million for the six months ended June 30, 2014, an increase of $62.7 million. The increase in operating income was primarily the result of an increase in the petroleum segment's operating income of $43.5 million due to higher refining margin, lower direct operating expenses and the flood insurance recovery. Nitrogen fertilizer segment operating income increased $18.3 million primarily as a result of higher net sales.

Interest Expense. Consolidated interest expense for the six months ended June 30, 2015 was $24.6 million, as compared to $19.4 million for the six months ended June 30, 2014. The increase of $5.2 million primarily resulted from lower capitalized interest for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

Gain (Loss) on Derivatives, net. For the six months ended June 30, 2015, the petroleum segment recorded a $64.0 million net loss on derivatives. This compares to a $145.3 million net gain on derivatives for the six months ended June 30, 2014. 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.

Other Income (Expense), net. Consolidated other income, net for the six months ended June 30, 2015 was $36.3 million, as compared to consolidated other expense, net of $2.1 million for the six months ended June 30, 2014. The increase of $38.4 million primarily related to a realized gain of $20.1 million recognized upon the sale of available-for-sale securities and an unrealized gain of $11.7 million recognized upon the reclassification of available-for-sale securities to trading securities based on management's ability and intent with respect to the securities, both of which occurred during the first quarter of 2015. The trading securities were subsequently sold during the three months ended June 30, 2015 for an additional gain of $0.4 million.

Income Tax Expense. Income tax expense for the six months ended June 30, 2015 was $82.1 million or 22.9% of income before income taxes, as compared to income tax expense for the six months ended June 30, 2014 of $114.6 million or 24.3% of income before income taxes. Our 2015 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 six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Petroleum Segment Summary Financial Results
Net sales	$	1,547.5		$	2,466.3		$	2,852.0		$	4,841.7
Cost of product sold(1)	1,180.9			2,172.6			2,237.1			4,236.0
Direct operating expenses(1)(2)	88.6			93.2			175.6			192.4
Major scheduled turnaround expenses	1.7			—			1.7			—
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Selling, general and administrative expenses(1)	18.6			17.9			36.7			36.6
Depreciation and amortization	34.2			30.7			68.2			60.2
Operating income	250.8			151.9			360.0			316.5
Interest expense and other financing costs	(10.4		)	(7.9		)	(21.7		)	(16.6		)
Interest income	0.1			0.1			0.2			0.2
Gain (loss) on derivatives, net	(12.6		)	35.9			(64.0		)	145.3
Other expense, net	(0.1		)	—			—			—
Income before income tax expense	227.8			180.0			274.5			445.4
Income tax expense	—			—			—			—
Net income	$	227.8		$	180.0		$	274.5		$	445.4

Gross profit(3)	$	269.4		$	169.8		$	396.7		$	353.1
Refining margin(4)	$	366.6		$	293.7		$	614.9		$	605.7
Adjusted Petroleum EBITDA(5)	$	194.3		$	192.9		$	356.0		$	387.0



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Refining margin(4)	$	19.12	$	15.22	$	16.47	$	16.17
Gross profit(3)	$	14.05	$	8.80	$	10.63	$	9.42
Direct operating expenses and major scheduled turnaround expenses(1)(2)	$	4.71	$	4.83	$	4.75	$	5.14
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6)	$	4.43	$	4.57	$	4.43	$	4.82
Barrels sold (barrels per day)(6)	224,031		224,295		220,876		220,760

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
			%			%			%			%
Refining Throughput and Production Data (bpd)
Throughput:
Sweet	192,691		87.1	193,032		87.2	184,082		84.4	185,412		85.2
Medium	1,082		0.5	1		—	3,841		1.8	1,789		0.8
Heavy sour	16,954		7.7	19,014		8.6	18,298		8.4	19,803		9.1
Total crude oil throughput	210,727		95.3	212,047		95.8	206,221		94.6	207,004		95.1
All other feedstocks and blendstocks	10,368		4.7	9,422		4.2	11,855		5.4	10,780		4.9
Total throughput	221,095		100.0	221,469		100.0	218,076		100.0	217,784		100.0
Production:
Gasoline	107,439		48.3	108,977		48.8	108,263		49.3	106,727		48.7
Distillate	95,881		43.1	94,931		42.6	92,675		42.1	91,933		41.9
Other (excluding internally produced fuel)	19,160		8.6	19,255		8.6	19,011		8.6	20,665		9.4
Total refining production (excluding internally produced fuel)	222,480		100.0	223,163		100.0	219,949		100.0	219,325		100.0
Product price (dollars per gallon):
Gasoline	$	1.87		$	2.87		$	1.67		$	2.77
Distillate	1.81			2.97			1.75			2.98



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX	$	57.95		$	102.99		$	53.34		$	100.84
Crude Oil Differentials:
WTI less WTS (light/medium sour)	(0.71		)	7.15			0.12			6.38
WTI less WCS (heavy sour)	9.57			19.22			11.60			20.05
NYMEX Crack Spreads:
Gasoline	26.02			23.20			22.34			20.70
Heating Oil	21.69			20.90			24.33			24.37
NYMEX 2-1-1 Crack Spread	23.85			22.05			23.33			22.53
PADD II Group 3 Basis:
Gasoline	(6.19		)	(7.06		)	(4.87		)	(5.98		)
Ultra Low Sulfur Diesel	(3.69		)	0.23			(4.10		)	(0.84		)
PADD II Group 3 Product Crack Spread:
Gasoline	19.83			16.14			17.47			14.72
Ultra Low Sulfur Diesel	18.00			21.13			20.23			23.53
PADD II Group 3 2-1-1	18.91			18.64			18.85			19.13


(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, flood insurance recovery 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 are 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 performance.

(5)

Petroleum EBITDA represents net income for the petroleum segment before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted Petroleum EBITDA represents Petroleum EBITDA adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery.

We present Adjusted Petroleum EBITDA because it is the starting point for calculating the Refining Partnership's available cash for distribution. Petroleum EBITDA and Adjusted Petroleum EBITDA are not recognized terms under GAAP and should not be substituted for net income as a measure of performance. Management believes that Petroleum EBITDA and Adjusted Petroleum EBITDA enable investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, help investors evaluate the petroleum segment's ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. Petroleum EBITDA and 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 net income for the petroleum segment to Petroleum EBITDA and Petroleum EBITDA to Adjusted Petroleum EBITDA for the three and six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Petroleum:
Petroleum net income	$	227.8		$	180.0		$	274.5		$	445.4
Add:
Interest expense and other financing costs, net of interest income	10.3			7.8			21.5			16.4
Income tax expense	—			—			—			—
Depreciation and amortization	34.2			30.7			68.2			60.2
Petroleum EBITDA	272.3			218.5			364.2			522.0
Add:
FIFO impacts (favorable), unfavorable(a)	(36.4		)	(24.3		)	(11.9		)	(45.9		)
Share-based compensation, non-cash	(0.1		)	0.7			0.1			1.2
Major scheduled turnaround expenses(b)	1.7			—			1.7			—
(Gain) loss on derivatives, net	12.6			(35.9		)	64.0			(145.3		)
Current period settlements on derivative contracts(c)	(28.5		)	33.9			(34.8		)	55.0
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Adjusted Petroleum EBITDA	$	194.3		$	192.9		$	356.0		$	387.0

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(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 Coffeyville refinery.


(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 total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.



	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(in millions)
Coffeyville Refinery Financial Results
Net sales	$	1,006.3		$	1,585.5	$	1,858.0		$	3,157.8
Cost of product sold (exclusive of depreciation and amortization)	764.8			1,398.5		1,465.7			2,757.2
Direct operating expenses (exclusive of depreciation and amortization)	51.2			53.7		101.5			107.1
Major scheduled turnaround expenses	1.7			—		1.7			—
Flood insurance recovery	(27.3		)	—		(27.3		)	—
Depreciation and amortization	19.5			18.8		38.9			36.8
Gross profit	$	196.4		$	114.5	$	277.5		$	256.7
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	52.9			53.7		103.2			107.1
Flood insurance recovery	(27.3		)	—		(27.3		)	—
Depreciation and amortization	19.5			18.8		38.9			36.8
Refining margin	$	241.5		$	187.0	$	392.3		$	400.6



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(dollars per barrel)
Coffeyville Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	20.27	$	15.61	$	16.82	$	17.31
Gross profit	$	16.49	$	9.55	$	11.89	$	11.09
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	4.43	$	4.48	$	4.43	$	4.63
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	4.03	$	4.12	$	4.00	$	4.19
Barrels sold (barrels per day)	144,183		143,412		142,587		141,226

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
		%		%		%		%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	112,867	81.2	112,670	80.6	106,734	77.3	107,294	78.5
Medium	1,082	0.8	1	—	3,841	2.8	744	0.5
Heavy sour	16,954	12.2	19,014	13.6	18,298	13.3	19,803	14.5
Total crude oil throughput	130,903	94.2	131,685	94.2	128,873	93.4	127,841	93.5
All other feedstocks and blendstocks	8,122	5.8	8,133	5.8	9,168	6.6	8,897	6.5
Total throughput	139,025	100.0	139,818	100.0	138,041	100.0	136,738	100.0
Production:
Gasoline	66,374	46.6	68,348	47.9	67,110	47.5	67,338	48.2
Distillate	62,257	43.7	61,403	43.0	60,843	43.0	59,624	42.6
Other (excluding internally produced fuel)	13,722	9.7	13,023	9.1	13,477	9.5	12,899	9.2
Total refining production (excluding internally produced fuel)	142,353	100.0	142,774	100.0	141,430	100.0	139,861	100.0



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Wynnewood Refinery Financial Results
Net sales	$	540.1	$	879.7	$	991.8	$	1,681.7
Cost of product sold (exclusive of depreciation and amortization)	415.9		774.2		771.4		1,478.7
Direct operating expenses (exclusive of depreciation and amortization)	37.5		39.8		74.1		85.4
Major scheduled turnaround expenses	—		—		—		—
Depreciation and amortization	12.5		10.1		25.1		20.1
Gross profit	$	74.2	$	55.6	$	121.2	$	97.5
Plus:
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	37.5		39.8		74.1		85.4
Depreciation and amortization	12.5		10.1		25.1		20.1
Refining margin	$	124.2	$	105.5	$	220.4	$	203.0

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(dollars per barrel)
Wynnewood Refinery Key Operating Statistics
Per crude oil throughput barrel:
Refining margin	$	17.10	$	14.42	$	15.74	$	14.16
Gross profit	$	10.21	$	7.60	$	8.66	$	6.80
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)	$	5.16	$	5.44	$	5.29	$	5.96
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold	$	5.16	$	5.41	$	5.23	$	5.93
Barrels sold (barrels per day)	79,848		80,883		78,289		79,534



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
		%		%		%		%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Sweet	79,824	97.3	80,362	98.4	77,348	96.6	78,118	96.4
Medium	—	—	—	—	—	—	1,045	1.3
Heavy sour	—	—	—	—	—	—	—	—
Total crude oil throughput	79,824	97.3	80,362	98.4	77,348	96.6	79,163	97.7
All other feedstocks and blendstocks	2,246	2.7	1,289	1.6	2,687	3.4	1,883	2.3
Total throughput	82,070	100.0	81,651	100.0	80,035	100.0	81,046	100.0
Production:
Gasoline	41,065	51.2	40,629	50.5	41,153	52.4	39,389	49.6
Distillate	33,624	42.0	33,528	41.7	31,832	40.5	32,309	40.6
Other (excluding internally produced fuel)	5,438	6.8	6,232	7.8	5,534	7.1	7,766	9.8
Total refining production (excluding internally produced fuel)	80,127	100.0	80,389	100.0	78,519	100.0	79,464	100.0

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Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014 (Petroleum Business)

Net Sales. Petroleum net sales were $1,547.5 million for the three months ended June 30, 2015 compared to $2,466.3 million for the three months ended June 30, 2014. The decrease of $918.8 million was largely the result of lower sales prices for the petroleum business' transportation fuels and by-products in addition to a small decrease in sales volumes. Overall sales volumes decreased approximately 1.0% for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014. For the three months ended June 30, 2015, the average sales price per gallon for gasoline of $1.87 decreased by approximately 34.8%, as compared to the three months ended June 30, 2014, and the average sales price per gallon for distillates of $1.81 for the three months ended June 30, 2015 decreased by approximately 39.1%, as compared to the three months ended June 30, 2014.



	Three Months Ended June 30, 2015					Three Months Ended June 30, 2014					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	10.3	$	78.59	$	812.4	10.4	$	120.59	$	1,253.6	(0.1	)	$	(441.2	)	$	(434.2	)	$	(7.0	)
Distillates	9.0	$	76.03	$	682.6	8.9	$	124.86	$	1,117.9	0.1		$	(435.3	)	$	(438.4	)	$	3.1


(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 $1,180.9 million for the three months ended June 30, 2015 compared to $2,172.6 million for the three months ended June 30, 2014. The decrease of $991.7 million was primarily the result of decreases in the cost of consumed crude and purchased products for resale. The decrease in consumed crude oil costs was due to a 43.7% decrease in crude oil prices. The average cost per barrel of crude oil consumed for the three months ended June 30, 2015 was $54.60 compared to $101.82 for the comparable period of 2014, a decrease of approximately 46.4%. Sales volumes of refined fuels decreased by approximately 1.0% 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 three months ended June 30, 2015, the petroleum business had a favorable FIFO inventory impact of $36.4 million compared to a favorable FIFO inventory impact of $24.3 million for the comparable period of 2014.

Refining margin per barrel of crude oil throughput increased to $19.12 for the three months ended June 30, 2015 from $15.22 for the three months ended June 30, 2014. Refining margin adjusted for FIFO impact was $17.22 per crude oil throughput barrel for the three months ended June 30, 2015, as compared to $13.96 per crude oil throughput barrel for the three months ended June 30, 2014. Gross profit per barrel increased to $14.05 for the three months ended June 30, 2015, as compared to gross profit per barrel of $8.80 in the equivalent period in 2014. The increase in refining margin and gross profit per barrel was primarily due to a stronger spread between crude oil and transportation fuel prices. The NYMEX 2-1-1 crack spread for the three months ended June 30, 2015 was $23.85 per barrel, an increase of approximately 8.2% over the NYMEX 2-1-1 crack spread of $22.05 per barrel for the three months ended June 30, 2014.

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 $90.3 million for the three months ended June 30, 2015 compared to direct operating expenses of $93.2 million for the three months ended June 30, 2014. The decrease of $2.9 million was primarily the result of decreases in expenses associated with energy and utility costs ($3.3 million), outside services ($1.9 million), labor ($1.8 million) and insurance costs ($1.0 million), partially offset by increases in environmental expenses ($2.9 million), turnaround expenses ($1.7 million) and repairs and maintenance costs ($1.2 million). Direct operating expenses per barrel of crude oil throughput for the three months ended June 30, 2015 decreased to $4.71 per barrel, as compared to $4.83 per barrel for the three months ended June 30, 2014. The decrease in the direct operating expenses per barrel of crude oil throughput is primarily a function of the lower overall expenses.

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Flood Insurance Recovery. During the three months ended June 30, 2015, the petroleum business received settlement proceeds from its environmental insurance carriers related to the June/July 2007 flood and crude oil discharge losses at CRRM’s Coffeyville refinery, of which $27.3 million was recorded as a flood insurance recovery. Refer to Part I, Item 1, Note 10 ("Commitments and Contingencies") for further details.

Operating Income. Petroleum operating income was $250.8 million for the three months ended June 30, 2015, as compared to operating income of $151.9 million for the three months ended June 30, 2014. The increase of $98.9 million was primarily the result of an increase in the refining margin ($72.9 million), a decrease in direct operating expenses ($2.9 million) and the flood insurance recovery ($27.3 million), partially offset by increases in depreciation and amortization ($3.5 million) and selling, general and administrative expenses ($0.7 million).

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014 (Petroleum Business)

Net Sales. Petroleum net sales were $2,852.0 million for the six months ended June 30, 2015 compared to $4,841.7 million for the six months ended June 30, 2014. The decrease of $1,989.7 million was largely the result of lower sales prices for the petroleum business' transportation fuels and by-products in addition to a small decrease in sales volumes. Overall sales volumes decreased approximately 1.2% for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014. For the six months ended June 30, 2015, the average sales price per gallon for gasoline of $1.67 decreased by approximately 39.7%, as compared to the six months ended June 30, 2014, and the average sales price per gallon for distillates of $1.75 for the six months ended June 30, 2015 decreased by approximately 41.3%, as compared to the six months ended June 30, 2014.



	Six Months Ended June 30, 2015					Six Months Ended June 30, 2014					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	21.1	$	70.33	$	1,480.0	20.3	$	116.21	$	2,354.0	0.8		$	(874.0	)	$	(965.4	)	$	91.4
Distillate	17.2	$	73.57	$	1,263.6	18.1	$	125.36	$	2,269.4	(0.9	)	$	(1,005.8	)	$	(890.4	)	$	(115.4	)


(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 $2,237.1 million for the six months ended June 30, 2015 compared to $4,236.0 million for the six months ended June 30, 2014. The decrease of $1,998.9 million was primarily the result of decreases in the cost of consumed crude and purchased products for resale. The decrease in consumed crude oil costs was due to a 47.1% decrease in crude oil prices. The average cost per barrel of crude oil consumed for the six months ended June 30, 2015 was $51.15 compared to $98.96 for the comparable period of 2014, a decrease of approximately 48.3%. Sales volumes of refined fuels decreased by approximately 1.2% 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 six months ended June 30, 2015, the petroleum business had a favorable FIFO inventory impact of $11.9 million compared to a favorable FIFO inventory impact of $45.9 million for the comparable period of 2014.

Refining margin per barrel of crude oil throughput increased to $16.47 for the six months ended June 30, 2015 from $16.17 for the six months ended June 30, 2014. Refining margin adjusted for FIFO impact was $16.15 per crude oil throughput barrel for the six months ended June 30, 2015, as compared to $14.95 per crude oil throughput barrel for the six months ended June 30, 2014. Gross profit per barrel increased to $10.63 for the six months ended June 30, 2015, as compared to gross profit per barrel of $9.42 in the equivalent period in 2014. The increase in refining margin and gross profit per barrel was primarily due to a stronger spread between crude oil and transportation fuel prices. The NYMEX 2-1-1 crack spread for the six months ended June 30, 2015 was $23.33 per barrel, an increase of approximately 3.6% over the NYMEX 2-1-1 crack spread of $22.53 per barrel for the six months ended June 30, 2014.

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compliance costs. Petroleum direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $177.3 million for the six months ended June 30, 2015 compared to direct operating expenses of $192.4 million for the six months ended June 30, 2014. The decrease of $15.1 million was primarily the result of decreases in expenses associated with energy and utility costs ($9.2 million), repairs and maintenance costs ($4.5 million) and labor ($3.5 million). The decrease was partially offset by increases in environmental expenses ($2.8 million) and turnaround expenses ($1.7 million). Direct operating expenses per barrel of crude oil throughput for the six months ended June 30, 2015 decreased to $4.75 per barrel, as compared to $5.14 per barrel for the six months ended June 30, 2014. The decrease in the direct operating expenses per barrel of crude oil throughput is primarily a function of the lower overall expenses.

Operating Income. Petroleum operating income was $360.0 million for the six months ended June 30, 2015, as compared to operating income of $316.5 million for the six months ended June 30, 2014. The increase of $43.5 million was primarily the result of an increase in the refining margin ($9.2 million), a decrease in direct operating expenses ($15.1 million) and the flood insurance recovery ($27.3 million), partially offset by increases in depreciation and amortization ($8.0 million) and selling, general and administrative expenses ($0.1 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 six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Nitrogen Fertilizer Business Financial Results
Net sales	$	80.8		$	77.2		$	173.9		$	157.5
Cost of product sold(1)	15.4			19.4			41.2			41.1
Direct operating expenses(1)	24.7			26.9			49.2			51.1
Major scheduled turnaround expenses	0.4			—			0.4			—
Selling, general and administrative(1)	4.6			5.3			9.1			9.9
Depreciation and amortization	7.0			6.8			13.8			13.5
Operating income	28.7			18.8			60.2			41.9
Interest expense and other financing costs	(1.7		)	(1.7		)	(3.4		)	(3.3		)
Income before income tax expense	27.0			17.1			56.8			38.6
Income tax expense	—			—			—			—
Net income	$	27.0		$	17.1		$	56.8		$	38.6

Adjusted Nitrogen Fertilizer EBITDA(2)	$	36.1		$	25.7		$	74.5		$	55.7

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Key Operating Statistics
Production (thousand tons):
Ammonia (gross produced)(3)	107.1			92.2			203.0			183.3
Ammonia (net available for sale)(3)(4)	4.4			3.2			19.1			12.1
UAN	253.5			223.4			505.6			480.6

Pet coke consumed (thousand tons)	128.2			117.3			253.1			242.1
Pet coke consumed (cost per ton)	$	25		$	27		$	27		$	28

Sales (thousand tons):
Ammonia	6.3			2.9			19.1			8.3
UAN	249.8			239.2			524.3			493.9

Product pricing at gate (dollars per ton)(5):
Ammonia	$	546		$	521		$	551		$	493
UAN	$	269		$	283		$	265		$	267

On-stream factor(6):
Gasification	100.0		%	94.2		%	99.7		%	96.5		%
Ammonia	99.3		%	88.1		%	96.9		%	90.1		%
UAN	96.6		%	85.9		%	97.2		%	91.4		%

Reconciliation of net sales (dollars in millions):
Sales net at gate	$	70.5		$	69.2		$	149.7		$	136.2
Freight in revenue	7.8			6.7			14.8			13.5
Hydrogen revenue	2.0			0.9			8.5			6.8
Other revenue	0.5			0.4			0.9			1.0
Total net sales	$	80.8		$	77.2		$	173.9		$	157.5



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Market Indicators
Natural gas NYMEX (dollars per MMBtu)	$	2.74	$	4.58	$	2.77	$	4.65
Ammonia — Southern Plains (dollars per ton)	546		561		550		501
UAN — Corn belt (dollars per ton)	305		333		309		332


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

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(2)

Nitrogen Fertilizer EBITDA represents nitrogen fertilizer net income adjusted for (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted Nitrogen Fertilizer EBITDA represents Nitrogen Fertilizer EBITDA adjusted for (i) share-based compensation, non-cash (ii) major scheduled turnaround expenses and (iii) loss on extinguishment of debt, as applicable. 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 net income as a measure of performance. Management believes that Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA enable investors and analysts to better understand the Nitrogen Fertilizer Partnership's ability to make distributions to its common unitholders, help investors and analysts evaluate its ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance by allowing investors to evaluate the same information used by management. Nitrogen Fertilizer EBITDA and 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 net income for the nitrogen fertilizer segment to Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA for the three and six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Nitrogen Fertilizer:
Nitrogen fertilizer net income	$	27.0	$	17.1	$	56.8	$	38.6
Add:
Interest expense and other financing costs, net	1.7		1.7		3.4		3.3
Income tax expense	—		—		—		—
Depreciation and amortization	7.0		6.8		13.8		13.5
Nitrogen Fertilizer EBITDA	35.7		25.6		74.0		55.4
Add:
Share-based compensation, non-cash	—		0.1		0.1		0.3
Major scheduled turnaround expenses	0.4		—		0.4		—
Adjusted Nitrogen Fertilizer EBITDA	$	36.1	$	25.7	$	74.5	$	55.7


(3)	Gross tons produced for ammonia represent total ammonia produced, including ammonia produced that was upgraded into UAN. Net tons available for sale represent ammonia available for sale that was not upgraded into UAN.


(4)	In addition to the produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 600 and 2,700 tons of ammonia during the three months ended June 30, 2015 and 2014, respectively. The Nitrogen Fertilizer Partnership acquired approximately 21,800 and 25,600 tons of ammonia during the six months ended June 30, 2015 and 2014, respectively.


(5)	Product pricing at gate 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 shutdown for installation of the waste heat boiler, PSA unit upgrade and the Linde air separation unit maintenance, the on-stream factors for the three months ended June 30, 2014 would have been 100.0% for gasifier, 94.9% for ammonia and 92.9% for UAN, and the on-stream factors for the six months ended June 30, 2014 would have been 99.4% for gasifier, 93.5% for ammonia and 95.0% for UAN.

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Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $80.8 million for the three months ended June 30, 2015 compared to $77.2 million for the three months ended June 30, 2014. The increase of $3.6 million was primarily the result of higher UAN sales volumes ($3.3 million), higher ammonia sales volumes ($1.9 million) and higher hydrogen sales volumes ($1.1 million), partially offset by lower UAN sales prices ($2.9 million). For the three months ended June 30, 2015, UAN and ammonia made up $74.8 million and $3.5 million of nitrogen fertilizer net sales, respectively. This compared to UAN and ammonia net sales of $74.4 million and $1.5 million, respectively, for the three months ended June 30, 2014. The following table demonstrates the impact of changes in sales volumes and pricing for UAN, ammonia and hydrogen for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014:



	Three Months Ended June 30, 2015					Three Months Ended June 30, 2014					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	249,790	$	299	$	74.8	239,216	$	311	$	74.4	10,574	$	0.4	$	(2.9	)	$	3.3
Ammonia	6,307	$	560	$	3.5	2,854	$	542	$	1.5	3,453	$	2.0	$	0.1		$	1.9
Hydrogen	207,543	$	10	$	2.0	92,967	$	10	$	0.9	114,576	$	1.1	$	—		$	1.1

(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 and ammonia sales volumes for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 was primarily attributable to increased production due to the May 2014 downtime. Product pricing at gate for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 decreased 4.9% for UAN and increased 4.8% for ammonia.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold (exclusive of depreciation and amortization) includes cost of freight and distribution expenses, pet coke expense and purchased ammonia costs. Cost of product sold (exclusive of depreciation and amortization) for the three months ended June 30, 2015 was $15.4 million compared to $19.4 million for the three months ended June 30, 2014. The $4.0 million decrease was primarily the result of lower distribution costs ($2.0 million) mostly due to the decrease in railcar regulatory inspections and repairs and ammonia purchases ($1.1 million). The decrease in railcar regulatory inspections and repairs is related to a smaller portion of the nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during the three months ended June 30, 2015, as compared to the three months ended June 30, 2014.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services, including turnaround, and environmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the three months ended June 30, 2015 were $25.1 million, as compared to $26.9 million for the three months ended June 30, 2014. The $1.8 million decrease resulted primarily from lower outside services ($0.7 million), refractory brick amortization ($0.7 million), utilities, net ($0.6 million) and repairs and maintenance ($0.5 million), partially offset by turnaround expenses ($0.4 million) and chemicals ($0.3 million).

Operating Income. Nitrogen fertilizer operating income was $28.7 million for the three months ended June 30, 2015, as compared to operating income of $18.8 million for the three months ended June 30, 2014. The increase of $9.9 million for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014, was the result of an increase in net sales ($3.6 million) and decreases in cost of product sold ($4.0 million), direct operating expenses ($1.8 million) and selling, general and administrative expenses ($0.7 million), partially offset by an increase in depreciation and amortization ($0.2 million).

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Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014 (Nitrogen Fertilizer Business)

Net Sales. Nitrogen fertilizer net sales were $173.9 million for the six months ended June 30, 2015 compared to $157.5 million for the six months ended June 30, 2014. The increase of $16.4 million was primarily the result of higher UAN sales volumes ($9.0 million), higher ammonia sales volumes ($5.6 million), higher hydrogen sales volumes ($1.4 million) and higher ammonia sales prices ($1.0 million), partially offset by lower UAN sales prices ($0.8 million). For the six months ended June 30, 2015, UAN and ammonia made up $153.7 million and $10.8 million of nitrogen fertilizer net sales, respectively. This compared to UAN and ammonia net sales of $145.5 million and $4.2 million, respectively, for the six months ended June 30, 2014. The following table demonstrates the impact of changes in sales volumes and pricing for UAN, ammonia and hydrogen for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014:



	Six Months Ended June 30, 2015					Six Months Ended June 30, 2014					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	524,330	$	293	$	153.7	493,886	$	295	$	145.5	30,444	$	8.2	$	(0.8	)	$	9.0
Ammonia	19,128	$	562	$	10.8	8,301	$	511	$	4.2	10,827	$	6.6	$	1.0		$	5.6
Hydrogen	807,821	$	11	$	8.5	671,431	$	10	$	6.8	136,390	$	1.7	$	0.3		$	1.4

(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 and ammonia sales volumes for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 was primarily attributable to increased production. Product pricing at gate for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 slightly decreased 0.7% for UAN and increased 11.8% for ammonia.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold (exclusive of depreciation and amortization) includes cost of freight and distribution expenses, pet coke expense and purchased ammonia costs. Cost of product sold (exclusive of depreciation and amortization) for the six months ended June 30, 2015 of $41.2 million was comparable to $41.1 million for the six months ended June 30, 2014. Higher costs incurred during the six months ended June 30, 2015 as a result of increased UAN and ammonia sales volumes discussed above were offset by lower distribution costs, mostly due to the decrease in railcar regulatory inspections and repairs. The decrease in railcar regulatory inspections and repairs is related to a smaller portion of the nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during the six months ended June 30, 2015, as compared to the six months ended June 30, 2014.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services, including turnaround, and environmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the six months ended June 30, 2015 were $49.6 million as compared to $51.1 million for the six months ended June 30, 2014. The $1.5 million decrease resulted primarily from lower outside services ($1.6 million) and utilities, net ($1.1 million) and refractory brick amortization ($1.1 million), partially offset by increases in labor ($0.8 million), repairs and maintenance ($0.6 million) and major scheduled turnaround expenses ($0.4 million).

Operating Income. Nitrogen fertilizer operating income was $60.2 million for the six months ended June 30, 2015, as compared to operating income of $41.9 million for the six months ended June 30, 2014. The increase of $18.3 million for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, was the result of the increase in net sales ($16.4 million) and decreases in direct operating expenses ($1.5 million) and selling, general and administrative expenses ($0.8 million), partially offset by increases in depreciation and amortization ($0.3 million) and cost of product sold ($0.1 million).

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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 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 outside of our control.

Cash Balance and Other Liquidity

As of June 30, 2015, we had consolidated cash and cash equivalents of $937.7 million. Of that amount, $437.5 million was cash and cash equivalents of CVR Energy, $433.2 million was cash and cash equivalents of the Refining Partnership and $67.0 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of July 28, 2015, we had consolidated cash and cash equivalents of approximately $966.6 million.

The Refining Partnership's senior secured asset based revolving credit facility (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 June 30, 2015, the Refining Partnership had $322.7 million available under the Amended and Restated ABL Credit Facility. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of June 30, 2015.

The Nitrogen Fertilizer Partnership's 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's credit facility matures in April 2016. The Nitrogen Fertilizer Partnership's credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of June 30, 2015, the Nitrogen Fertilizer Partnership had $25.0 million available under its credit facility. As discussed in Note 8 ("Long-Term Debt") to Part I, Item I of this Report, the Nitrogen Fertilizer Partnership's credit facility matures in April 2016 and the $125.0 million principal portion of the term loan is presented as a current liability as of June 30, 2015. The Nitrogen Fertilizer Partnership is considering various capital structure and refinancing options in association with the credit facility maturity. We anticipate these options will be adequate to fund the cash requirements of the maturing 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 distributions will be made to all common unitholders. At June 30, 2015, we currently hold approximately 66% and 53% of the Refining Partnership's and the Nitrogen Fertilizer Partnership's common units outstanding, respectively. The amount of each distribution will be determined pursuant to each general partner's calculation of available cash for the applicable quarter. The general partner of each partnership, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of each general partner's distribution policy, funds held by the Refining Partnership and the Nitrogen Fertilizer Partnership will not be available for our use, and we as a unitholder expect to receive our applicable percentage of the distribution of funds within 60 days following each quarter. The Refining Partnership and the Nitrogen Fertilizer Partnership do not have a legal obligation to pay distributions and there is no guarantee that they will pay any distributions on the units in any quarter.

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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 June 30, 2015, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.

The 2022 Notes 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. After January 23, 2013, the 2022 Notes were no longer secured. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. CVR Energy, CVR Partners and Coffeyville Resources Nitrogen Fertilizers ("CRNF") (a subsidiary of the Nitrogen Fertilizer Partnership) are not guarantors.

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, as amended. 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 membership interest 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 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

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as "incremental funds" under the indenture. The Refining Partnership was in compliance with the covenants as of June 30, 2015, 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 prior 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 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 three-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 six-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 June 30, 2015.

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

Borrowings under the Nitrogen Fertilizer Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility is 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 June 30, 2015, no amounts were drawn under the Nitrogen Fertilizer Partnership's $25.0 million revolving credit facility.

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Nitrogen Fertilizer Partnership Interest Rate Swaps

The Nitrogen Fertilizer Partnership has determined that the two Interest Rate Swaps agreements entered into in 2011 qualify for hedge accounting treatment. The impact recorded for each of the three months ended June 30, 2015 and 2014 was $0.3 million in interest expense. For the three months ended June 30, 2015 and 2014, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0 and $0.1 million, respectively, which was unrealized in accumulated other comprehensive income. The impact recorded for each of the six months ended June 30, 2015 and 2014 was $0.5 million in interest expense. For the six months ended June 30, 2015 and 2014, the Nitrogen Fertilizer Partnership recognized a decrease in fair value of the interest rate swap agreements of $0.1 million and $0.2 million, respectively, 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.

The following table summarizes our total actual capital expenditures for the six months ended June 30, 2015 and current estimated capital expenditures for the remainder of 2015 by operating segment and major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:



	Six Months Ended June 30, 2015		2015 Estimate⁽¹⁾
	Actual		Low		High
	(in millions)
Petroleum Business (the Refining Partnership):
Coffeyville refinery:
Maintenance	$	21.4	$	104.0	$	110.0
Growth	26.3		88.0		95.0
Coffeyville refinery total capital spending	47.7		192.0		205.0
Wynnewood refinery:
Maintenance	13.8		44.0		48.0
Growth	5.9		10.0		12.0
Wynnewood refinery total capital spending	19.7		54.0		60.0
Other Petroleum:
Maintenance	5.5		16.0		20.0
Growth	5.2		18.0		20.0
Other petroleum total capital spending	10.7		34.0		40.0
Petroleum business total capital spending	78.1		280.0		305.0
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
Maintenance	3.6		10.0		12.0
Growth	2.4		6.0		10.0
Nitrogen fertilizer business total capital spending	6.0		16.0		22.0
Corporate	2.6		8.0		10.0
Total capital spending	$	86.7	$	304.0	$	337.0


(1)	Includes amounts already spent during the six months ended June 30, 2015.

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,

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is approximately $122.5 million with an anticipated completion date in the second quarter of 2016. As of June 30, 2015, the Refining Partnership had incurred costs of approximately $37.8 million, excluding capitalized interest, for the hydrogen plant.

During 2015, the Refining Partnership plans to build two crude oil storage tanks in Cushing, which is expected to provide an additional 500,000 barrels of crude storage in total. The estimated cost of this project, excluding capitalized interest, is approximately $14.0 million to $15.0 million with an anticipated completion date in the fourth quarter of 2015. As of June 30, 2015, the Refining Partnership had incurred costs of approximately $5.7 million, excluding capitalized interest, for the crude oil storage tanks.

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:



	Six Months Ended June 30,
	2015			2014
	(unaudited)
	(in millions)
Net cash provided by (used in):
Operating activities	$	376.4		$	405.5
Investing activities	(18.7		)	(193.0		)
Financing activities	(173.7		)	(55.9		)
Net increase in cash and cash equivalents	$	184.0		$	156.6

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 six months ended June 30, 2015 were $376.4 million. The positive cash flow from operating activities generated over this period was primarily driven by $276.8 million of net income before noncontrolling interest and favorable impacts to other working capital. Trade working capital for the six months ended June 30, 2015 resulted in a net cash outflow of $54.0 million, which was attributable to increases in accounts receivable ($43.7 million) and inventory ($19.9 million). The increase in accounts receivable was primarily due to increased receivables related to gasoline sales due to higher gasoline pricing. The increase in inventory was primarily due to increased crude oil inventory due to higher crude oil volumes and pricing, partially offset by lower distillate inventory due to lower pricing. Other working capital activities resulted in a net cash inflow of $68.8 million, which was primarily related to an increase in due to parent ($65.3 million) and a decrease in prepaid expenses and other current assets ($34.2 million), partially offset by a decrease in other current liabilities ($25.8 million). The increase in due to parent is a result of the timing of tax payments to American Entertainment Properties Corporation ("AEPC") which shifted from a due from position at December 31, 2014 to a due to position as of June 30, 2015. The decrease in prepaid expenses and other current assets was primarily due to the sale of trading securities, a reduction in prepaid insurance and the timing of payments related to certain other prepaid items. The decrease in other current liabilities was primarily due to decreases in the biofuel blending obligation and decreases in personnel accruals.

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Net cash flows provided by operating activities for the six months ended June 30, 2014 were $405.5 million. The positive cash flow from operating activities generated over the period was primarily driven by $357.7 million of net income before noncontrolling interest and $58.0 million of favorable impacts to other working capital. Trade working capital for the six months ended June 30, 2014 resulted in a net cash inflow of $19.9 million, which was attributable to an increase in accounts payable ($28.6 million), partially offset by increases in accounts receivable ($6.6 million) and inventory ($2.1 million). The increase in accounts payable was largely the result of increased payables for crude purchases and timing of payments at the petroleum business. Other working capital activities resulted in a net cash inflow of $58.0 million, which was primarily related to increases in due to parent ($27.9 million), other current liabilities ($13.1 million) and accrued income taxes ($11.0 million). The increase in due to parent and accrued income taxes was the result of timing of tax payments made to AEPC and other tax authorities. The increase in other current liabilities was primarily attributable to an increase in accruals related to the biofuel blending obligation at the petroleum business.

Cash Flows Used in Investing Activities

Net cash used in investing activities for the six months ended June 30, 2015 was $18.7 million compared to $193.0 million for the six months ended June 30, 2014. The decrease of $174.3 million was the result of decreased purchases of available-for-sale securities ($78.3 million), proceeds received from the sale of available-for-sale securities ($68.0 million) and decreased capital spending ($28.2 million) for the six months ended June 30, 2015. The decrease in capital spending was primarily the result of lower spending at the petroleum business following the completion of several larger projects in the fourth quarter of 2014.

Cash Flows Used In Financing Activities

Net cash used in financing activities for the six months ended June 30, 2015 was approximately $173.7 million, as compared to $55.9 million for the six months ended June 30, 2014. The net cash used in financing activities for the six months ended June 30, 2015 was primarily attributable to dividend payments to common stockholders of $86.8 million and distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $86.2 million. The net cash used in financing activities for the six months ended June 30, 2014 was primarily attributable to dividend payments to common stockholders of $130.2 million and distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $88.9 million, partially offset by proceeds of $163.9 million from the Refining Partnership's Second Underwritten Offering.

As of and for the six months ended June 30, 2015, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility.

Contractual Obligations

As of June 30, 2015, 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 six months ended June 30, 2015 from those disclosed in our 2014 Form 10-K.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of June 30, 2015, as defined within the rules and regulations of the SEC.

Recent Accounting Pronouncements

Refer to Part I, Item 1, Note 2 ("Recent Accounting Pronouncements") of this Report for a discussion of recent accounting pronouncements applicable to the Company.

Critical Accounting Policies

Our critical accounting policies are disclosed in the "Critical Accounting Policies" section of our 2014 Form 10-K. No modifications have been made to our critical accounting policies.

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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 six months ended June 30, 2015 does not differ materially from that discussed under Part II — Item 7A of our 2014 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 June 30, 2015, the Refining Partnership had open commodity hedging instruments consisting of 8.1 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at June 30, 2015 was a net unrealized gain of $19.6 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 $8.1 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 3.5%, 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. The Nitrogen Fertilizer Partnership is party to two swap agreements for the purpose of hedging the interest rate risk associated with a portion of its credit facility. The credit facility is discussed in Note 8 ("Long-Term Debt") and the interest rate swap agreements are discussed in Note 12 ("Derivative Financial Instruments") to Part I, Item 1 of this Report.

Foreign Currency Exchange

Given that our business is currently based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of the petroleum business' Canadian crude oil purchases are conducted in Canadian dollars. Commitments for future periods under this agreement reflect the exchange rate between the Canadian Dollar and the U.S. Dollar as of the end of the reporting period. Based on the short period of time between the delivery and settlement of purchases of crude oil in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of June 30, 2015, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our

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

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 June 30, 2015 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 1 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 2014 Form 10-K.

Item 6. Exhibits



Exhibit Number		Exhibit Title
10.1*		First Amendment to Amended and Restated Crude Oil Supply Agreement, dated as of June 8, 2015, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC.
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 June 30, 2015 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.



July 30, 2015	By:	/s/ JOHN J. LIPINSKI
		Chief Executive Officer and President
		(Principal Executive Officer)

July 30, 2015	By:	/s/ SUSAN M. BALL
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer)