Edgar Filing: CVR Refining, LP

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if smaller reporting company.)

CVRR Q2 2015 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended 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: 001-35781

CVR Refining, LP

(Exact name of registrant as specified in its charter)



Delaware	37-1702463
(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 147,600,000 common units outstanding at July 28, 2015.

CVR REFINING, LP 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 Statement of Changes in Partners’ Capital – Six Months Ended June 30, 2015 (unaudited)	8

	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2015 and 2014 (unaudited)	9

	Notes to the Condensed Consolidated Financial Statements — June 30, 2015 (unaudited)	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	51

Part II. Other Information

Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 6.	Exhibits	52

Signatures		53

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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.

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.

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.

CVR Energy — CVR Energy, Inc., a publicly traded company listed on the NYSE under the ticker symbol "CVI," which indirectly owns our general partner and a majority of our common units.

CVR Partners — CVR Partners, LP, a publicly traded limited partnership listed on the NYSE under the ticker symbol "UAN," which produces and markets nitrogen fertilizers in the form of urea ammonium nitrate ("UAN") and ammonia.

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.

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.

general partner — CVR Refining GP, LLC, our general partner, which is an indirect wholly-owned subsidiary of CVR Energy.

Group 3 — A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include our 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.

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

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

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

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.

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

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.

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.

Second Underwritten Offering — The second underwritten offering of 7,475,000 common units of CVR Refining, LP, 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 our refineries. This process involves the shutdown and inspection of major processing units and occurs every four to five years.

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

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

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

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

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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 REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2015		December 31, 2014
	(unaudited)
	(in millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	433.2	$	370.2
Accounts receivable, net of allowance for doubtful accounts of $0.4 and $0.3, including $0.3 and $0.5 due from affiliates at June 30, 2015 and December 31, 2014, respectively	169.7		130.0
Inventories	313.9		293.8
Prepaid expenses and other current assets, including $1.6 and $4.1 due from affiliates at June 30, 2015 and December 31, 2014, respectively	80.7		94.5
Total current assets	997.5		888.5
Property, plant and equipment, net of accumulated depreciation	1,494.9		1,487.1
Deferred financing costs, net	7.2		8.1
Other long-term assets	16.7		34.1
Total assets	$	2,516.3	$	2,417.8
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Note payable and capital lease obligations	$	1.5	$	1.4
Accounts payable, including $5.1 and $8.9 due to affiliates at June 30, 2015 and December 31, 2014, respectively	272.7		269.9
Personnel accruals, including $3.3 and $1.6 due to affiliates at June 30, 2015 and December 31, 2014, respectively	17.0		18.6
Accrued taxes other than income taxes	28.7		24.7
Accrued expenses and other current liabilities, including $6.1 and $6.9 due to affiliates at June 30, 2015 and December 31, 2014, respectively	55.3		69.4
Total current liabilities	375.2		384.0
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion, including $31.5 due to affiliates at June 30, 2015 and December 31, 2014	579.2		580.0
Other long-term liabilities, including $0.9 and $1.0 due to affiliates at June 30, 2015 and December 31, 2014, respectively	3.9		3.7
Total long-term liabilities	583.1		583.7
Commitments and contingencies
Partners' capital:
Common unitholders, 147,600,000 units issued and outstanding at June 30, 2015 and December 31, 2014	1,558.0		1,450.1
General partner interest	—		—
Total partners' capital	1,558.0		1,450.1
Total liabilities and partners' capital	$	2,516.3	$	2,417.8

See accompanying notes to the condensed consolidated financial statements.

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CVR REFINING, LP 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 unit data)
Net sales	$	1,547.5		$	2,466.3		$	2,852.0		$	4,841.7
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)	1,180.9			2,172.6			2,237.1			4,236.0
Direct operating expenses (exclusive of depreciation and amortization)	90.3			93.2			177.3			192.4
Flood insurance recovery	(27.3		)	—			(27.3		)	—
Selling, general and administrative expenses (exclusive of depreciation and amortization)	18.6			17.9			36.7			36.6
Depreciation and amortization	34.2			30.7			68.2			60.2
Total operating costs and expenses	1,296.7			2,314.4			2,492.0			4,525.2
Operating income	250.8			151.9			360.0			316.5
Other income (expense):
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		)	—			—			—
Total other income (expense)	(23.0		)	28.1			(85.5		)	128.9
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

Net income per common unit – basic	$	1.54		$	1.22		$	1.86		$	3.02
Net income per common unit – diluted	$	1.54		$	1.22		$	1.86		$	3.02

Weighted-average common units outstanding:
Basic	147.6			147.6			147.6			147.6
Diluted	147.6			147.6			147.6			147.6

See accompanying notes to the condensed consolidated financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL



	Common Units Issued	Common Unitholders			General Partner Interest		Total Partners' Capital
	(unaudited)
	(in millions, except unit data)
Balance at December 31, 2014	147,600,000	$	1,450.1		$	—	$	1,450.1
Share-based compensation - Affiliates	—	0.1			—		0.1
Cash distributions to common unitholders - Affiliates	—	(116.7		)	—		(116.7		)
Cash distributions to common unitholders - Non-affiliates	—	(50.0		)	—		(50.0		)
Net income	—	274.5			—		274.5
Balance at June 30, 2015	147,600,000	$	1,558.0		$	—	$	1,558.0

See accompanying notes to the condensed consolidated financial statements.

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CVR REFINING, LP 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	$	274.5		$	445.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	68.2			60.2
Allowance for doubtful accounts	0.1			(0.4		)
Amortization of deferred financing costs	0.9			0.9
Loss on disposition of assets	0.6			—
Share-based compensation	4.0			5.2
(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	(40.3		)	(6.4		)
Inventories	(20.1		)	(4.5		)
Prepaid expenses and other current assets	7.7			6.7
Other long-term assets	—			(0.1		)
Accounts payable	3.8			18.1
Accrued expenses and other liabilities	(20.3		)	22.8
Other long-term liabilities	0.2			(0.2		)
Net cash provided by operating activities	308.5			457.4
Cash flows from investing activities:
Capital expenditures	(78.1		)	(105.3		)
Net cash used in investing activities	(78.1		)	(105.3		)
Cash flows from financing activities:
Payment of capital lease obligations	(0.7		)	(0.6		)
Proceeds from June 2014 issuance of common units, net of offering costs	—			163.9
Redemption of common units from CVR Refining Holdings, LLC - June 2014	—			(164.1		)
Distributions to common unitholders – affiliates	(116.7		)	(158.4		)
Distributions to common unitholders – non-affiliates	(50.0		)	(52.7		)
Net cash used in financing activities	(167.4		)	(211.9		)
Net increase in cash and cash equivalents	63.0			140.2
Cash and cash equivalents, beginning of period	370.2			279.8
Cash and cash equivalents, end of period	$	433.2		$	420.0

Supplemental disclosures:
Cash paid for interest net of capitalized interest of $1.2 and $5.1 in 2015 and 2014, respectively	$	20.7		$	15.6
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	$	18.9		$	20.2
Change in accounts payable related to construction in process additions	$	(1.1	)	$	(10.3	)

See accompanying notes to the condensed consolidated financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2015

(unaudited)

(1) Formation of the Partnership, Organization and Nature of Business

CVR Refining, LP and subsidiaries (referred to as "CVR Refining" or the "Partnership") is an independent petroleum refiner and marketer of high value transportation fuels. CVR Refining is a Delaware limited partnership, formed in September 2012 by Coffeyville Resources, LLC (referred to as "CRLLC"), a wholly owned subsidiary of CVR Energy, Inc. (referred to as "CVR Energy") in contemplation of an initial public offering. As of June 30, 2015, CRLLC owned 100% of the Partnership's general partner interest and approximately 66% of the Partnership's limited partner interests. As of June 30, 2015, Icahn Enterprises L.P. ("IEP") and its affiliates owned approximately 82% of CVR Energy.

Offerings of CVR Refining, LP

CVR Refining completed the initial public offering of its common units representing limited partner interests (the "Initial Public Offering") on January 23, 2013. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." On May 20, 2013, the 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 Energy, 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 all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings, LLC ("CVR Refining Holdings") held approximately 71% of all outstanding limited partner interests.

On June 30, 2014, the 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 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 all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.

On July 24, 2014, the 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 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 $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 all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, LLC ("CVR Refining GP"), which holds a non-economic general partner interest.

The Partnership's general partner manages the Partnership's activities subject to the terms and conditions specified in the Partnership's 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 CVR Refining Holdings as the sole member of the Partnership's general partner and not by the board of directors of the general partner. The members of the board of directors of the Partnership's general partner are not elected by the 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.

The Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cash for distribution for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter and will generally be distributed within 60 days of quarter end. The partnership

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

agreement does not require that the Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Partnership can change the distribution policy at any time.

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

(2) Basis of Presentation

The accompanying condensed consolidated financial statements have been 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"). 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 Refining'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 condensed consolidated financial statements include certain selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization) that CVR Energy and its affiliates incurred on behalf of the Partnership. These related party transactions are governed by the services agreement originally entered into on December 31, 2012. See Note 14 ("Related Party Transactions") for additional discussion of the services agreement and billing and allocation of certain costs. The amounts charged or allocated to the Partnership are not necessarily indicative of the cost that the Partnership would have incurred had it operated as an independent entity.

In the opinion of the Partnership's management, the accompanying condensed consolidated financial statements and related notes reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Partnership as of June 30, 2015 and December 31, 2014, the results of operations of the Partnership for the three and six month periods ended June 30, 2015 and 2014, the changes in partners' capital for the Partnership for the six month period ended June 30, 2015 and the cash flows of the Partnership 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.

(3) Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("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 effective date if they choose. The Partnership 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 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

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

be applied on a retrospective basis. Early adoption is permitted. The Partnership expects that the adoption of ASU 2015-03 will result in a reclassification of certain debt issuance costs on the Condensed Consolidated Balance Sheets.

(4) Share-Based Compensation

Certain employees of CVR Refining and employees of CVR Energy who perform services for CVR Refining participate in the equity compensation plans of CVR Refining's affiliates. Accordingly, CVR Refining has recorded compensation expense for these plans in accordance with SAB Topic 1-B ("Allocations of Expenses and Related Disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity") and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Refining has been allocated 100% to CVR Refining. For employees of CVR Energy performing services for CVR Refining, CVR Refining recorded share-based compensation relative to the percentage of time spent by each employee providing services to CVR Refining as compared to the total calculated share-based compensation by CVR Energy.

Long-Term Incentive Plan—CVR Energy

CVR Energy has a Long-Term Incentive Plan ("CVR Energy LTIP") that 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 CVR Energy LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy's or its subsidiaries' (including CVR Refining) employees, officers, consultants and directors.

Restricted Stock Units

Through the CVR Energy LTIP, shares of restricted common stock were previously granted to employees of CVR Energy and CVR Refining. 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 of CVR Energy and related Transaction Agreement dated April 18, 2012 between CVR Energy and an affiliate of IEP (the "Transaction Agreement") triggered a modification to outstanding awards under the CVR Energy 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.

In 2012 and 2013, restricted stock units and dividend equivalent rights were granted to certain employees of CVR Energy and its subsidiaries (including CVR Refining). 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 share of CVR Energy's common stock, plus (b) the cash value of all dividends declared and paid per share of CVR Energy's common stock from the grant date to and including the vesting date. The awards are remeasured at each subsequent reporting date until they vest.

Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at June 30, 2015, there was approximately $0.4 million of total unrecognized compensation cost related to restricted stock units and associated dividend equivalent rights to be recognized over a weighted-average period of approximately 0.5 years.

Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that may occur from time to time. The unrecognized compensation expense has been determined by the number of restricted stock units and associated dividend equivalent rights and respective allocation percentages for individuals for whom, as of June 30, 2015, compensation expense has been allocated to the Partnership. Total compensation expense recorded for the three months ended June 30, 2015 and 2014 was approximately $(0.1) million and $0.7 million, respectively. Total compensation expense recorded for the six months ended June 30, 2015 and 2014 was approximately $0.1 million and $1.2 million, respectively. CVR Refining is not responsible for payment of CVR Energy restricted stock unit awards, and accordingly, the expenses recorded have been reflected as increases to partners' capital.

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Performance Unit Awards

Mr. Lipinski's performance unit awards were fully vested as of December 31, 2014 and reimbursed as of March 31, 2015 with no remaining performance unit awards outstanding. Total compensation expense recorded for the three and six months ended June 30, 2014 related to the performance unit awards was approximately $0.8 million and $1.5 million, respectively.

Incentive Unit Awards

In 2013, 2014 and 2015, CVR Energy 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 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 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.

Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at June 30, 2015, there was approximately $3.8 million of total unrecognized compensation cost related to the incentive units and associated distribution equivalent rights to be recognized over a weighted-average period of approximately 1.4 years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that may occur from time to time. The unrecognized compensation expense has been determined by the number of incentive units and associated distribution equivalent rights and respective allocation percentages for individuals for whom, as of June 30, 2015 compensation expense has been allocated to the Partnership. Total compensation expense recorded for the three months ended June 30, 2015 and 2014 related to the awards was $0.6 million and $0.5 million, respectively. Total compensation expense recorded for the six months ended June 30, 2015 and 2014 related to the awards was $1.6 million and $1.0 million, respectively. The Partnership will be responsible for reimbursing CVR Energy for its allocated portion of the awards.

As of June 30, 2015 and December 31, 2014, the Partnership had a liability of $2.1 million and $0.5 million, respectively, for its allocated portion of non-vested incentive units and associated distribution equivalent rights, which is recorded in accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets.

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 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 Partnership.

In 2013 and 2014, awards of phantom units and distribution equivalent rights were granted to employees of the Partnership and its subsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Partnership. 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 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 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 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:



	Phantom 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 $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 $2.0 million and $1.5 million, respectively.

As of June 30, 2015 and December 31, 2014, the 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 and accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets.

In December 2014, CVR Energy 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 canceled 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 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 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 for the three and six months ended June 30, 2015 and the liability related to the SARs as of June 30, 2015 were not material.

(5) Inventories

Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress 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 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.

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Inventories consisted of the following:



	June 30, 2015		December 31, 2014
	(in millions)
Finished goods	$	149.4	$	163.5
Raw materials and precious metals	114.5		78.8
In-process inventories	18.4		20.6
Parts and supplies	31.6		30.9
	$	313.9	$	293.8

(6) 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	$	28.0	$	27.7
Buildings	46.0		45.4
Machinery and equipment	2,050.0		2,015.5
Automotive equipment	22.5		21.2
Furniture and fixtures	8.9		8.4
Leasehold improvements	0.8		0.8
Construction in progress	98.4		61.2
	2,254.6		2,180.2
Accumulated depreciation	759.7		693.1
Total property, plant and equipment, net	$	1,494.9	$	1,487.1

Capitalized interest recognized as a reduction in interest expense for the three months ended June 30, 2015 and 2014 totaled approximately $0.8 million and $2.8 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 $5.1 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.

(7) Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, renewable identification numbers ("RINs") and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.7 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 $3.3 million and $2.8 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 also include allocated share-based compensation from CVR Energy, as discussed in Note 4 ("Share-Based Compensation"). Direct operating expenses exclude depreciation and amortization of approximately $31.9 million and $28.9 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 $63.8 million and $56.8 million, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated legal expenses, treasury, accounting, marketing, human resources, information technology and maintaining the corporate and administrative offices in Texas and Kansas. Selling, general and administrative expenses also include allocated

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share-based compensation from CVR Energy as discussed in Note 4 ("Share-Based Compensation"). Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.6 million and $0.3 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 expenses exclude depreciation and amortization of approximately $1.1 million and $0.6 million, respectively.

(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
Intercompany credit facility	31.5			31.5
Capital lease obligations	49.2			49.9
Total debt	580.7			581.4
Current portion of capital lease obligations	(1.5		)	(1.4		)
Long-term debt, net of current portion	$	579.2		$	580.0

2022 Senior Notes

The Partnership has $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022 (the "2022 Notes") outstanding, which were issued by CVR Refining, LLC ("Refining LLC") and Coffeyville Finance Inc. ("Coffeyville Finance") on October 23, 2012. The 2022 Notes were issued at par and mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.

The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the 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 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 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 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 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

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a fixed charge coverage ratio financial covenant, as defined therein. The 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 Partnership 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.

Intercompany Credit Facility

The Partnership maintains a $250.0 million senior unsecured revolving credit facility (the "intercompany credit facility") with CRLLC as the lender, to be used to fund growth capital expenditures. The intercompany credit facility has a term of six years and bears interest at a rate of LIBOR plus 3% per annum, payable quarterly.

The intercompany credit facility contains covenants that require the Partnership to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of the Partnership's business and financial status as it may reasonably require, including, but not limited to, copies of its unaudited quarterly financial statements and its audited annual financial statements. The Partnership was in compliance with the covenants of the intercompany credit facility as of June 30, 2015.

In addition, the intercompany credit facility contains customary events of default, including, among others, failure to pay any sum payable when due; the occurrence of a default under other indebtedness in excess of $25.0 million; and the occurrence of an event that results in either (i) CRLLC no longer directly or indirectly controlling the general partner, or (ii) CRLLC and its affiliates no longer owning a majority of the Partnership's equity interests. As of June 30, 2015, the Partnership had borrowings of $31.5 million outstanding and $218.5 million available under the intercompany credit facility.

Capital Lease Obligations

CVR Refining 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) Partners' Capital and Partnership Distributions

The Partnership had two types of partnership interests outstanding at June 30, 2015:


•	common units; and


•	a general partner interest, which is not entitled to any distributions, and which is held by the general partner.

At June 30, 2015, the Partnership had a total of 147,600,000 common units issued and outstanding, of which 97,315,764 common units were owned by CVR Refining Holdings representing approximately 66% of the total Partnership units outstanding.

The board of directors of the Partnership's general partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the general partner following the end of such quarter. Available cash for distribution for each quarter will generally equal Adjusted EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for future major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of the general partner deems necessary or appropriate, if any. Adjusted EBITDA represents EBITDA (net income before interest expense and other financing costs, net of interest income; income tax expense; and depreciation and amortization) 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)

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current period settlements on derivative contracts and (vii) flood insurance recovery. 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 general partner. The board of directors of the general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the board of directors of the general partner to make distributions at all.

The following is a summary of cash distributions paid to the Partnership's 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, except per unit data)
Amount paid to CVR Refining Holdings, LLC and affiliates	$	38.2	$	78.5	$	116.7
Amounts paid to non-affiliates	16.4		33.7		50.0
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

(10) Net Income per Common Unit

The Partnership's net income is allocated wholly to the common units as the general partner does not have an economic interest. Basic and diluted net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period and, when applicable, giving effect to unvested common units granted under the CVR Refining LTIP. There were no dilutive awards outstanding during the three and six months ended June 30, 2015 and 2014, as all unvested awards under the CVR Refining LTIP were liability-classified awards.

The following table illustrates the Partnership's calculation of net income per common unit 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, except per unit data)
Net income	$	227.8	$	180.0	$	274.5	$	445.4
Net income per common unit, basic	$	1.54	$	1.22	$	1.86	$	3.02
Net income per common unit, diluted	$	1.54	$	1.22	$	1.86	$	3.02
Weighted-average common units outstanding, basic	147.6		147.6		147.6		147.6
Weighted-average common units outstanding, diluted	147.6		147.6		147.6		147.6

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(11) Commitments and Contingencies

Leases and Unconditional Purchase Obligations

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



	Operating Leases		Unconditional Purchase Obligations⁽¹⁾
	(in millions)
Six months ending December 31, 2015	$	0.8	$	97.2
Year Ending December 31,
2016	1.2		119.9
2017	0.4		113.1
2018	0.2		111.5
2019	0.2		110.8
Thereafter	0.3		791.3
	$	3.1	$	1,343.8

(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 Refining leases various equipment, including real properties, under long-term operating leases expiring at various dates. For the three months ended June 30, 2015 and 2014, lease expense totaled approximately $0.4 million and $0.6 million, respectively. For the six months ended June 30, 2015 and 2014, lease expense totaled approximately $0.9 million and $1.2 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR Refining'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, CVR Refining has long-term commitments to purchase storage capacity and pipeline transportation services. For the three months ended June 30, 2015 and 2014, total expense of approximately $31.8 million and $32.2 million, respectively, was incurred related to long-term commitments. For the six months ended June 30, 2015 and 2014, total expense of approximately $61.9 million and $63.2 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 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 expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.

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Litigation

From time to time, CVR Refining 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 Refining previously reported in its 2014 Form 10-K or 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.

Environmental, Health and Safety ("EHS") Matters

CRRM, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Coffeyville Resources Terminal, LLC ("CRT") and Wynnewood Refining Company, LLC ("WRC") 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, CRCT, WRC and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution. Therefore, CRRM, 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, 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 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.

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As previously reported, CVR Refining is party to, or otherwise subject to: (i) 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; (ii) the Mobile Source Air Toxic II ("MSAT II") rule which requires reductions of benzene in gasoline; (iii) 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 (iv) "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, 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 CVR Refining'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, CVR Refining's Condensed Consolidated Balance Sheets 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 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 $7.2 million and $26.4 million, respectively. For the six months ended June 30, 2015 and 2014, capital expenditures were approximately $17.8 million and $60.1 million, respectively. These expenditures were incurred for environmental compliance and efficiency of the operations.

(12) Fair Value Measurements

In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820"), the Partnership 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 or liabilities


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


•	Level 3 — Significant unobservable inputs (including CVR Refining's own assumptions in determining the fair value)

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

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
Other current assets (derivative agreements)	$	—	$	14.4		$	—	$	14.4
Other long-term assets (derivative agreements)	—		8.5			—		8.5
Total Assets	$	—	$	22.9		$	—	$	22.9
Other current liabilities (derivative agreements)	—		(4.8		)	—		(4.8		)
Other current liabilities (biofuel blending obligation)	—		(13.8		)	—		(13.8		)
Total Liabilities	$	—	$	(18.6	)	$	—	$	(18.6	)



	December 31, 2014
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Other current assets (derivative agreements)	$	—	$	25.0		$	—	$	25.0
Other long-term assets (derivative agreements)	—		22.3			—		22.3
Total Assets	$	—	$	47.3		$	—	$	47.3
Other current liabilities (biofuel blending obligation)	—		(49.6		)	—		(49.6		)
Total Liabilities	$	—	$	(49.6	)	$	—	$	(49.6	)

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 CVR Refining's derivative instruments and uncommitted biofuel blending obligation. Additionally, the fair value of the debt issuances is disclosed in Note 8 ("Long-Term Debt"). The 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. CVR Refining had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2015.

(13) 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

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

CVR Refining has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR Refining 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

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

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.

CVR Refining 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, CVR Refining 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 June 30, 2015 and 2014, CVR Refining recognized net losses of $0.4 million and $0.2 million, respectively. For the six months ended June 30, 2015 and 2014, CVR Refining 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

CVR Refining 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, CVR Refining 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, CVR Refining 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, CVR Refining 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.

Counterparty Credit Risk

CVR Refining'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. CVR Refining 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. CVR Refining also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Condensed Consolidated Balance Sheets. As of June 30, 2015, the counterparty credit risk adjustment was not material to the condensed consolidated financial statements. Additionally, CVR Refining 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 CVR Refining 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 CVR Refining. As a result of the right to setoff, CVR Refining's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. 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.

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

The offsetting assets and liabilities for CVR Refining'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 accrued expenses 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

The offsetting assets and liabilities for CVR Refining'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

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

(14) Related Party Transactions

CVR Refining is party to, or otherwise subject to certain agreements with CVR Energy and its subsidiaries (including CVR Partners and its subsidiary) that govern the business relations among each party including: the (i) Feedstock and Shared Services Agreement; (ii) Coke Supply Agreement; (iii) Environmental Agreement; (iv) Services Agreement and (v) Limited Partnership Agreement. Except as otherwise described below, there have been no new developments or material changes to these agreements from those provided in the 2014 Form 10-K.

Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable and prepaid expenses and other current assets on the Condensed Consolidated Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CVR Refining and CRRM with respect to these agreements are included in accounts payable, personnel accruals, accrued expenses and other current liabilities, long-term debt and other long-term liabilities, on CVR Refining's Condensed Consolidated Balance Sheets.

Feedstock and Shared Services Agreement

CRRM is party to a feedstock and shared services agreement with Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF") under which the two parties provide feedstocks and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM's Coffeyville, Kansas refinery and CRNF's nitrogen fertilizer plant.

Pursuant to the feedstock agreement, CRRM and CRNF have agreed to transfer hydrogen to one another; provided, CRRM is not required to sell hydrogen to CRNF if such hydrogen is required for operation of CRRM's refinery, if such sale would adversely affect the Partnership's classification as a partnership for federal income tax purposes, or if such sale would not be in CRRM's best interest. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining, when applicable. Net monthly receipts of hydrogen from CRNF have been reflected in cost of product sold (exclusive of depreciation and amortization) for CVR Refining. For the three months ended June 30, 2015 and 2014, CVR Refining recognized $2.0 million and $0.9 million, respectively, of cost of product sold (exclusive of depreciation and amortization) related to the purchase of hydrogen from the nitrogen fertilizer facility. For the six months ended June 30, 2015 and 2014, CVR Refining recognized $8.5 million and $6.8 million, respectively, of cost of product sold (exclusive of depreciation and amortization) related to the purchase of hydrogen from the nitrogen fertilizer facility. At June 30, 2015 and December 31, 2014, there were approximately $0.3 million and $1.3 million, respectively, of payables included in accounts payable on the Condensed Consolidated Balance Sheets associated with unpaid balances related to hydrogen.

CRNF is also obligated to make available to CRRM any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by CRNF in a commercially reasonable manner. Direct operating expenses associated with nitrogen purchased by CRRM from CRNF for the three months ended June 30, 2015 and 2014, were approximately $0 and $0.3 million, respectively. Direct operating expenses associated with nitrogen purchased by CRRM from CRNF for the six months ended June 30, 2015 and 2014, were approximately $0 and $0.5 million, respectively. No amounts were paid by CRNF to CRRM for any of the periods presented.

The agreement also provides a mechanism pursuant to which CRNF transfers a tail gas stream to CRRM. For each of the three and six months ended June 30, 2015 and 2014, direct operating expenses generated from the purchase of tail gas from CRNF were nominal.

In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF agreed to pay CRRM the cost of installing the pipe over the next three years and in the fourth year provided an additional 15% to cover the cost of capital. At June 30, 2015 and December 31, 2014, an asset of approximately $0 and $0.1 million, respectively, was included in other current assets. Additionally, at June 30, 2015 and December 31, 2014, a liability of approximately $0.2 million was included in other current liabilities and approximately $0.9 million and $1.0 million, respectively, was included in other non-current liabilities in the Condensed Consolidated Balance Sheets.

At June 30, 2015 and December 31, 2014, payables of approximately $0.1 million and $0.2 million, respectively, were included in accounts payable on the Condensed Consolidated Balance Sheets associated with amounts yet to be paid related to components of the feedstock and shared services agreement, other than amounts associated with hydrogen purchases. At June 30,

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

2015 and December 31, 2014, receivables of approximately $0.8 million and $1.1 million, respectively, were included in prepaid expenses and other current assets on the Condensed Consolidated Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.

Coke Supply Agreement

CRRM is party to a coke supply agreement with CRNF pursuant to which CRRM supplies CRNF with pet coke. This agreement provides that CRRM must deliver to CRNF during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at CRRM's Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CRNF is also obligated to purchase this annual required amount. If during a calendar month CRRM produces more than 41,667 tons of pet coke, then CRNF will have the option to purchase the excess at the purchase price provided for in the agreement. If CRNF declines to exercise this option, CRRM may sell the excess to a third party.

The price CRNF pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for urea ammonium nitrate ("UAN"), or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.

CRNF pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. Amounts payable under the feedstock and shared services agreements can be offset with any amount receivable for pet coke.

Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $2.1 million and $2.3 million for the three months ended June 30, 2015 and 2014, respectively. Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $4.2 million and $4.6 million for the six months ended June 30, 2015 and 2014, respectively. Receivables of approximately $0.3 million and $0.5 million related to the coke supply agreement were included in accounts receivable on the Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014, respectively.

Services Agreement

CVR Refining obtains certain management and other services from CVR Energy pursuant to a services agreement between the Partnership, CVR Refining GP and CVR Energy. Net amounts incurred under the services agreement for the three and six months ended June 30, 2015 and 2014 were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Direct operating expenses (exclusive of depreciation and amortization)	$	4.7	$	5.5	$	9.3	$	10.9
Selling, general and administrative expenses (exclusive of depreciation and amortization)	13.4		13.0		26.0		26.5
Total	$	18.1	$	18.5	$	35.3	$	37.4

At June 30, 2015 and December 31, 2014, payables and liabilities of approximately $9.8 million and $13.6 million, respectively, were included in accounts payable, personnel accruals and accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement.

Limited Partnership Agreement

The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person to perform services for the Partnership or for its general partner in connection with operating the Partnership). For the three months ended June 30, 2015 and 2014, approximately $1.7 million and $1.8 million, respectively, were incurred

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2015

(unaudited)

under the partnership agreement. For the six months ended June 30, 2015 and 2014, approximately $4.0 million and $3.3 million, respectively, were incurred under the partnership agreement.

Intercompany Credit Facility

As of June 30, 2015, the Partnership had borrowings of $31.5 million outstanding under the intercompany credit facility. For each of the three and six months ended June 30, 2015 and 2014, the Partnership paid $0.2 million and $0.5 million, respectively, of interest to CRLLC. See Note 8 ("Long-Term Debt") for additional discussion of the intercompany credit facility.

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. The Partnership participates in Insight Portfolio Group's buying group through its relationship with CVR Energy. The Partnership may purchase a variety of goods and services as members of the buying group at prices and on terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.

(15) Subsequent Events

Distribution

On July 29, 2015, the board of directors of the Partnership's general partner declared a cash distribution for the second quarter of 2015 to the 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.

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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 distributions, 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 that 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:


•	our ability to make cash distributions on the common units;


•	the price volatility of crude oil, other feedstocks and refined products, and variable nature of our distributions;


•	the ability of our general partner to modify or revoke our distribution policy at any time;


•	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;


•	our ability in the future to obtain an adequate crude oil supply pursuant to supply agreements or at all;


•	our continued access to crude oil and other feedstock and refined products pipelines;


•	the level of competition from other petroleum refiners;


•	changes in our credit profile;


•	potential operating consequences from accidents, fire, severe weather, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime;


•	our continued ability to secure gasoline and diesel RINs, as well as environmental and other governmental permits necessary for the operation of our business;

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


•	costs of compliance with existing or new environmental laws and regulations, as well as the potential liabilities arising from, and capital expenditures required to, remediate current or future contamination;


•	the seasonal nature of our business;


•	our dependence on significant customers;


•	our potential inability to obtain or renew permits;


•	our ability to continue safe, reliable operations without unplanned maintenance events prior to and when approaching the end-of-cycle turnaround operations;


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


•	the risk of security breaches;


•	our lack of asset diversification;


•	the potential loss of our transportation cost advantage over our competitors;


•	our ability to comply with employee safety laws and regulations;


•	potential disruptions in the global or U.S. capital and credit markets;


•	the success of our acquisition and expansion strategies;


•	our reliance on CVR Energy's senior management team;


•	the risk of a substantial increase in costs or work stoppages associated with negotiating collective bargaining agreements with the unionized portion of our workforce;


•	the potential shortage of skilled labor or loss of key personnel;


•	successfully defending against third-party claims of intellectual property infringement;


•	our indebtedness;


•	our potential inability to generate sufficient cash to service all of our indebtedness;


•	the limitations contained in our debt agreements that limit our flexibility in operating our business;


•	the dependence on our subsidiaries for cash to meet our debt obligations;


•	our limited operating history as a stand-alone entity;


•	potential increases in costs and distraction of management resulting from the requirements of being a publicly traded partnership;


•	exemptions we will rely on in connection with the NYSE corporate governance requirements;


•	risks relating to our relationships with CVR Energy;


•	risks relating to the control of our general partner by CVR Energy;


•	the conflicts of interest faced by our senior management team, which operates both us and CVR Energy, and our general partner;


•	limitations on duties owed by our general partner that are included in the partnership agreement;

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•	changes in our treatment as a partnership for U.S. income or state tax purposes; and


•	instability and volatility in the capital and credit markets.

All forward-looking statements contained in this Report only speak 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.

Partnership Overview

We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the underserved Group 3 of the PADD II region of the United States. Our business includes a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). In addition, our 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 owned and leased pipelines) that transports crude oil to our Coffeyville refinery from our 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 located at throughput terminals on Magellan and NuStar refined petroleum products distribution systems and (5) approximately 4.5 million barrels of combined refinery related storage capacity.

Our Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Our 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), we make 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 our Coffeyville refinery through our gathering system and by a pipeline owned by Plains that runs from Cushing to our Broome Station facility. We maintain capacity on the Keystone and Spearhead pipelines from Canada to Cushing. We began shipping on contracted capacity maintained on the Pony Express pipeline in May 2015. We also have 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. We also maintain leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Our 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 our 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. Our 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, we 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 our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the second quarter of 2015 was $3.35 per barrel compared to $1.16 per barrel in the second quarter of 2014.

Second Underwritten Offering

On June 30, 2014, we 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. We 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 all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.

On July 24, 2014, we 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. We 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

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common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.

Subsequent to the closing of the underwriters' option of the Second Underwritten Offering and as of June 30, 2015, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests in addition to owning 100% of our general partner.

Major Influences on Results of Operations

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

The prices of crude oil and other feedstocks and refined products 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 our 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. We are also subject to the Renewable Fuel Standard ("RFS") of the United States Environmental Protection Agency (the "EPA"), which requires us to either blend "renewable fuels" in with our transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"), in lieu of blending.

The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. 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 our business will be more accurately defined by the November 30, 2015 ruling. The future cost of RINs for our 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 our petroleum products, as well as the fuel blending performed at our 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, we currently estimate that the total cost of RINs will be approximately $110.0 million to $150.0 million for the year ending December 31, 2015.

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If sufficient RINs are unavailable for purchase at times when we seek to purchase RINs, or if we have to pay a significantly higher price for RINs or if we are subject to penalties as a result of delays in our ability to timely deliver RINs to the EPA, our business, financial condition and results of operations could be materially adversely affected.

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

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

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces, resulting in prices that reflect the logistics cost for Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refineries is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

We are significantly affected by developments in the markets in which we operate. 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.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the six months ended June 30, 2015, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $6.1 million.

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

Safe and reliable operations at our refineries are key to our financial performance and results of operations. Unscheduled downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the

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availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. Our Coffeyville refinery completed the first phase of 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. We completed a turnaround at our Wynnewood refinery in December 2012, and the next turnaround is scheduled to occur in the spring of 2017.

Agreements with Affiliates

In connection with the initial public offering of CVR Energy and the transfer of the nitrogen fertilizer business to CVR Partners in October 2007, CVR Energy and its subsidiaries entered into a number of agreements with CVR Partners and its subsidiary that govern the business relations among CVR Partners, CVR Energy and their subsidiaries and affiliates and the general partner of CVR Partners. In connection with CVR Partners' initial public offering, CVR Energy, directly or through its subsidiaries, amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Partners. In connection with our Initial Public Offering, some of the subsidiaries party to these agreements became subsidiaries of CVR Refining.

These intercompany agreements include (i) the pet coke supply agreement under which CVR Partners purchases the pet coke we generate at our Coffeyville refinery for use in CVR Partners' manufacture of nitrogen fertilizer; (ii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iii) a raw water and facilities sharing agreement, which allocates raw water resources between the Coffeyville refinery and the nitrogen fertilizer plant; (iv) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners; (v) a cross-easement agreement, which grants easements to both parties for operational facilities, pipelines, equipment, access, and water rights; and (vi) an environmental agreement which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville refinery and the nitrogen fertilizer plant. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

We are also party to a number of agreements with CVR Energy and its subsidiaries, including (i) a $250.0 million senior unsecured revolving credit facility (the "intercompany credit facility") between CRLLC and us and (ii) a services agreement, pursuant to which we are managed by CVR Energy.

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 us with crude oil and intermediation logistics, which helps us to reduce our 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 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)	$	1.2		$	2.8		$	4.0		$	5.2
(Gain) loss on derivatives, net	12.6			(35.9		)	64.0			(145.3		)
Major scheduled turnaround expenses(b)	1.7			—			1.7			—
Flood insurance recovery(c)	(27.3		)	—			(27.3		)	—

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(a)	Represents impact of share-based compensation awards, including allocated expense.


(b)	Represents expense associated with major scheduled turnaround activities at the Coffeyville refinery.


(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 11 ("Commitments and Contingencies") for further details.

Distributions to CVR Refining Unitholders

Refer to Part I, Item 1, Note 9 ("Partners' Capital and Partnership Distributions") and Part I, Item 2 - "Results of Operations" for discussion of the current available cash for distribution policy and Part I, Item 1, Note 9 ("Partners' Capital and Partnership Distributions") for a summary of cash distributions paid to the Partnership’s unitholders during 2015.

Results of Operations

The following tables summarize the financial data and key operating statistics for CVR Refining and our subsidiaries 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.

Net sales consist principally of sales of refined fuel, and are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, versus lower value finished products, such as pet coke.

Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See "—Major Influences on Results of Operations." We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold. Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization).

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Consolidated Statements of Operations Data
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 EBITDA(5)	$	194.3		$	192.9		$	356.0		$	387.0
Available cash for distribution(6)	$	144.2		$	142.8		$	256.0		$	286.8



	As of June 30, 2015		As of December 31, 2014
			(audited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	433.2	$	370.2
Working capital	622.3		504.5
Total assets	2,516.3		2,417.8
Total debt, including current portion	580.7		581.4
Total partners' capital	1,558.0		1,450.1



	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	$	160.0		$	199.2		$	308.5		$	457.4
Investing activities	(36.4		)	(47.4		)	(78.1		)	(105.3		)
Financing activities	(112.5		)	(145.2		)	(167.4		)	(211.9		)
Net cash flow	$	11.1		$	6.6		$	63.0		$	140.2

Capital expenditures for property, plant and equipment	$	36.4		$	47.4		$	78.1		$	105.3

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	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)(7)	$	4.43	$	4.57	$	4.43	$	4.82
Barrels sold (barrels per day)(7)	224,031		224,295		220,876		220,760



	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

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	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)	Our cost of product sold, direct operating expenses and selling, general and administrative expenses for the three and six months ended June 30, 2015 and 2014 are shown exclusive of depreciation and amortization, which is comprised of the following components:



	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	$	1.7	$	1.5	$	3.3	$	2.8
Depreciation and amortization excluded from direct operating expenses	31.9		28.9		63.8		56.8
Depreciation and amortization excluded from selling, general and administrative expenses	0.6		0.3		1.1		0.6
Total depreciation and amortization	$	34.2	$	30.7	$	68.2	$	60.2


(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 the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3)

Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery and depreciation and amortization. Each of the components used in this calculation are taken directly from our Condensed Consolidated Statements of Operations. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.

(4)

Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that management believes is important to investors in evaluating the performance of our refineries as a general indication of the amount above our cost of product sold at which we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from our Condensed Consolidated Statements of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput

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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 our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.

(5)

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, 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 EBITDA because it is the starting point for our available cash for distribution. 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 our ability to make distributions to our common unitholders, help investors 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	$	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
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 EBITDA	$	194.3		$	192.9		$	356.0		$	387.0

(a)

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


(b)	Represents expense associated with certain major scheduled turnaround activities performed at our 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 the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.

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(6)

Available cash for distribution is generally equal to Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for future major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our 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 our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash for distribution should not be considered in isolation or as an alternative to net income or operating income, as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash for distribution as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure.



	Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
	(in millions, except per unit data)
Reconciliation of Adjusted EBITDA to Available cash for distribution
Adjusted EBITDA	$	194.3		$	356.0
Adjustments:
Less:
Cash needs for debt service	(10.0		)	(20.0		)
Reserves for environmental and maintenance capital expenditures	(31.3		)	(62.5		)
Reserves for future turnarounds	(8.8		)	(17.5		)
Available cash for distribution	$	144.2		$	256.0
Available cash for distribution, per unit	$	0.98		$	1.74
Common units outstanding (in thousands)	147,600			147,600


(7)	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

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	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



	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

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	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



	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

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	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

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Net Sales. 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 our transportation fuels and by-products in addition to a small decrease in our 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, our 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. For the three months ended June 30, 2015, our average sales price per gallon for distillates of $1.81 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
	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	)
Distillate	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. 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. Our 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% over the same period. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and

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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, we 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 of our 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) include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. 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 lower overall expenses.

Flood Insurance Recovery. During the three months ended June 30, 2015, we received settlement proceeds from our environmental insurance carriers related to the June/July 2007 flood and crude oil discharge losses at our Coffeyville refinery, of which $27.3 million was recorded as a flood insurance recovery. Refer to Part I, Item 1, Note 11 ("Commitments and Contingencies") for further details.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and CRLLC and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $18.6 million for the three months ended June 30, 2015 compared to $17.9 million for the three months ended June 30, 2014. The increase of $0.7 million was primarily the result of higher personnel related costs.

Operating Income. 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).

Interest Expense. Interest expense for the three months ended June 30, 2015 was $10.4 million, as compared to $7.9 million for the three months ended June 30, 2014. The increase of $2.5 million resulted primarily 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, we 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. We enter into over-the-counter commodity swap contracts to fix the margin on a portion of our future gasoline and distillate production.

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Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Net Sales. 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 our 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, our 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. For the six months ended June 30, 2015, our average sales price per gallon for distillates of $1.75 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
	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. 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. Our 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 volume 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 our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the six months ended June 30, 2015, we 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 our 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.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. 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 lower overall expenses.

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Flood Insurance Recovery. During the six months ended June 30, 2015, we received settlement proceeds from our environmental insurance carriers related to the June/July 2007 flood and crude oil discharge losses at our Coffeyville refinery, of which $27.3 million was recorded as a flood insurance recovery. Refer to Part I, Item 1, Note 11 ("Commitments and Contingencies") for further details.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and CRLLC and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) of $36.7 million for the six months ended June 30, 2015 and $36.6 million for the six months ended June 30, 2014 remained relatively consistent over the comparable periods.

Operating Income. 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).

Interest Expense. Interest expense for the six months ended June 30, 2015 was $21.7 million, as compared to $16.6 million for the six months ended June 30, 2014. The increase of $5.1 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, we 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. We enter into over-the-counter commodity swap contracts to fix the margin on a portion of our future gasoline and distillate production.

Liquidity and Capital Resources

Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations and paying distributions to our unitholders, as discussed further below.

We believe that our cash flows from operations and existing cash and cash equivalents, along with borrowings, as necessary, under the Amended and Restated ABL Credit Facility and the $250.0 million intercompany credit facility, will be sufficient to satisfy the anticipated cash requirements associated with our existing 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, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.

Our general partner's current policy is to distribute an amount equal to the available cash we generate each quarter to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance our growth externally, the growth in our business, and our liquidity, may be negatively impacted.

Cash Balance and Other Liquidity

As of June 30, 2015 we had cash and cash equivalents of $433.2 million. Working capital at June 30, 2015 was $622.3 million, consisting of $997.5 million in current assets and $375.2 million in current liabilities. Working capital at December 31, 2014 was $504.5 million, consisting of $888.5 million in current assets and $384.0 million in current liabilities. As of July 28, 2015, we had cash and cash equivalents of $458.7 million.

The senior secured asset based revolving credit facility (the "Amended and Restated ABL Credit Facility") provides us 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 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 swing line loans and 90% of the total facility commitment for letters of credit. The intercompany credit facility provides us with borrowing availability of up to $250.0 million.

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As of June 30, 2015, we had $322.7 million available under the Amended and Restated ABL Credit Facility and $218.5 million available under the intercompany credit facility. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of June 30, 2015.

Borrowing Activities

2022 Notes. On October 23, 2012, CVR Refining, LLC ("Refining LLC") and 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, LLC (a subsidiary of CVR Partners) 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 our 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. 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.

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

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

In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to any person other than qualifying owners (as defined in the indenture), (2) liquidation or dissolution of Refining LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the membership interest of Refining LLC.

The indenture governing the 2022 Notes imposes covenants that restrict our ability to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of our 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 our 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 Ratings Services and Moody's Investors Service, 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 us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge

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coverage ratio is not less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. We were in compliance with the covenants as of 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, we entered into the Amended and Restated ABL Credit Facility with Wells Fargo, as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced CRLLC's prior ABL credit facility. Under the Amended and Restated ABL Credit Facility, we assumed CRLLC's position as borrower and its obligations under the Amended and Restated ABL Credit Facility upon the closing of the Initial Public Offering on January 23, 2013. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swing line loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The 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 may 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. We are 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 lenders under the Amended and Restated ABL Credit Facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).

The 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 facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. We were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2015.

Intercompany Credit Facility. The Partnership maintains a $250.0 million intercompany credit facility with CRLLC as the lender to be used to fund growth capital expenditures. The intercompany credit facility has a term of six years and bears interest at a rate of LIBOR plus 3% per annum.

The intercompany credit facility contains covenants that require us to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of our business and financial status as it may reasonably require, including, but not limited to, copies of our unaudited quarterly financial statements and our audited annual financial statements. We were in compliance with the covenants of the intercompany credit facility as of June 30, 2015.

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In addition, the intercompany credit facility contains customary events of default, including, among others, failure to pay any sum payable when due; the occurrence of a default under other indebtedness in excess of $25.0 million; and the occurrence of an event that results in either (i) CRLLC no longer directly or indirectly controlling our general partner, or (ii) CRLLC and its affiliates no longer owning a majority of our equity interests. As of June 30, 2015, we had borrowings of $31.5 million outstanding and $218.5 million available under the intercompany credit facility.

Capital Spending

We divide our 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 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)
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:
Maintenance	5.5		16.0		20.0
Growth	5.2		18.0		20.0
Other total capital spending	10.7		34.0		40.0
Total capital spending	$	78.1	$	280.0	$	305.0


(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 Partnership approved the construction of a hydrogen plant at our Coffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide additional hydrogen that is needed for environmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $122.5 million with an anticipated completion date in the second quarter of 2016. The project will be financed by the $250.0 million intercompany credit facility. As of June 30, 2015, we had incurred costs of approximately $37.8 million, excluding capitalized interest, for the hydrogen plant.

During 2015, we plan 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, we had incurred costs of approximately $5.7 million, excluding capitalized interest, for the crude oil storage tanks.

Our ability to make payments on and to refinance our indebtedness, to fund budgeted capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. Our ability to refinance our indebtedness is also subject to the availability of the credit markets. This, to a certain extent, is subject to refining

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spreads and general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our Amended and Restated ABL Credit Facility or the intercompany credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need or seek to refinance all or a portion of our indebtedness on or before maturity depending on market conditions. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all. In addition, we 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 that we will be able to do so at prices that we 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	$	308.5		$	457.4
Investing activities	(78.1		)	(105.3		)
Financing activities	(167.4		)	(211.9		)
Net increase in cash and cash equivalents	$	63.0		$	140.2

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 approximately $308.5 million. The positive cash flow from operating activities generated over this period was primarily driven by $274.5 million of net income. Trade working capital for the six months ended June 30, 2015 resulted in a net cash outflow of $56.6 million which was attributable to increases in accounts receivable ($40.3 million) and inventory ($20.1 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 outflow of $12.6 million, which was primarily related to a decrease in other current liabilities ($20.3 million), partially offset by a decrease in prepaid expenses and other current assets ($7.7 million). The decrease in other current liabilities was primarily due to decreases in the biofuel blending obligation and personnel accruals. The decrease in prepaid expenses and other current assets was due to a decrease in prepaid insurance and the timing of payments related to certain other prepaid items.

Net cash flows provided by operating activities for the six months ended June 30, 2014 were approximately $457.4 million. The positive cash flow from operating activities generated over this period was primarily driven by $445.4 million of net income and $29.5 million of favorable impacts to other working capital. Trade working capital for the six months ended June 30, 2014 resulted in a cash inflow of approximately $7.2 million, which was primarily attributable to an increase in accounts payable ($18.1 million), partially offset by increases in accounts receivable ($6.4 million) and inventory ($4.5 million). The increase in accounts payable was largely the result of increased payables for crude purchases and timing of payments. Other working capital activities resulted in net cash inflow of $29.5 million, which was primarily related to an increase in other current liabilities ($22.8 million) and a decrease in prepaid expenses and other current assets ($6.7 million). The increase in other current liabilities was primarily due to an increase in accruals related to the biofuel blending obligation. The decrease in prepaid expenses and other current assets was due to a decrease in prepaid insurance.

Cash Flows Used In Investing Activities

Net cash used in investing activities for the six months ended June 30, 2015 was $78.1 million compared to $105.3 million for the six months ended June 30, 2014. The decrease in cash used in investing activities was the result of a $27.2 million

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decrease in capital expenditures during the six months ended June 30, 2015 compared to the six months ended June 30, 2014. The decrease in capital spending was primarily the result of lower spending 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 $167.4 million compared to $211.9 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 distributions to our common unitholders of $166.7 million (including $116.7 million to affiliates). The net cash used in financing activities for the six months ended June 30, 2014 was primarily attributable to distributions to our common unitholders of $211.1 million (including $158.4 million to affiliates).

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. As of June 30, 2015, the Partnership had borrowings of $31.5 million outstanding under the intercompany 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 3 ("Recent Accounting Pronouncements") of this Report for a discussion of recent accounting pronouncements applicable to the Partnership.

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.

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, as all our products 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.

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Commodity Price Risk

At June 30, 2015, we had open commodity hedging instruments consisting of 8.1 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at 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.

Foreign Currency Exchange

Given that our operations are based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of our 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 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 11 ("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)/15d-14(a) Certification of Chief Executive Officer and President.
31.2*		Rule 13a-14(a)/15d-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 Refining, LP'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 Statement of Changes in Partners' Capital (unaudited), (4) Condensed Consolidated Statements of Cash Flows (unaudited), and (5) 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 which 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 Partnership 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 Partnership'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 Partnership 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 Refining, LP

	By:	CVR Refining GP, LLC, its general partner

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)