Edgar Filing: CVR Refining, LP

Large accelerated filer o

Accelerated filer o

Non-accelerated filer þ

Smaller reporting company o

(Do not check if smaller reporting company.)

CVRR Q3 2013 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

	For the quarterly period ended September 30, 2013

OR

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

	For the transition period from to .

Commission file number: 001-35781

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 October 29, 2013.

CVR REFINING, LP AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2013



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

	Condensed Consolidated Balance Sheets — September 30, 2013 (unaudited) and December 31, 2012	5

	Condensed Consolidated and Combined Statements of Operations — Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	6

	Condensed Consolidated Statement of Changes in Partners’ Capital – Nine Months Ended September 30, 2013 (unaudited)	7

	Condensed Consolidated and Combined Statements of Cash Flows — Nine Months Ended September 30, 2013 and 2012 (unaudited)	8

	Notes to the Condensed Consolidated and Combined Financial Statements — September 30, 2013 (unaudited)	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61

Item 4.	Controls and Procedures	62

Part II. Other Information

Item 1.	Legal Proceedings	63

Item 1A.	Risk Factors	63

Item 6.	Exhibits	63

Signatures		64

Table of Contents

GLOSSARY OF SELECTED TERMS

The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2013 (this “Report”).

2-1-1 crack spread—The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.

barrel—Common unit of measure in the oil industry which equates to 42 gallons.

blendstocks—Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.

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

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

capacity—Capacity is defined as the throughput a process unit is capable of sustaining, either on a 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.

distillates—Primarily diesel fuel, kerosene and jet fuel.

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.

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.

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.

Table of Contents

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.

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.

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

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

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

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

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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2013		December 31, 2012
	(unaudited)
ASSETS	(in millions, except unit data)
Current assets:
Cash and cash equivalents	$	250.5	$	153.1
Accounts receivable, net of allowance for doubtful accounts of $2.5 and $1.9, including $0.3 and $0.6 due from affiliates at September 30, 2013 and December 31, 2012, respectively	233.4		204.5
Inventories	647.3		499.5
Prepaid expenses and other current assets, including $1.3 and $0.9 due from affiliates at September 30, 2013 and December 31, 2012, respectively	134.6		27.0
Insurance receivable	—		1.3
Total current assets	1,265.8		885.4
Property, plant, and equipment, net of accumulated depreciation	1,395.6		1,351.6
Deferred financing costs, net	10.5		14.4
Insurance receivable	4.0		4.0
Other long-term assets, including $0.1 and $0.4 due from affiliates at September 30, 2013 and December 31, 2012, respectively	10.6		3.1
Total assets	$	2,686.5	$	2,258.5
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Note payable and capital lease obligations	$	1.2	$	1.1
Accounts payable, including $13.4 and $0.4 due to affiliates at September 30, 2013 and December 31, 2012, respectively	349.1		364.7
Personnel accruals	12.5		14.0
Accrued taxes other than income taxes	19.5		29.5
Accrued expenses and other current liabilities, including $0.2 due to affiliates at September 30, 2013 and December 31, 2012	64.5		93.4
Total current liabilities	446.8		502.7
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion, including $11.5 million due to affiliates at September 30, 2013	561.7		772.1
Accrued environmental liabilities, net of current portion	1.4		1.6
Other long-term liabilities, including $1.2 and $1.3 due to affiliates at September 30, 2013 and December 31, 2012, respectively	1.3		1.3
Total long-term liabilities	564.4		775.0
Commitments and contingencies
Partners’ capital:
Common unitholders, 147,600,000 units issued and outstanding at September 30, 2013	1,675.3		—
General partner’s interest	—		—
Limited partner interest	—		980.8
Total partners’ capital	1,675.3		980.8
Total liabilities and partners’ capital	$	2,686.5	$	2,258.5

See accompanying notes to the condensed consolidated and combined financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(unaudited)
	(in millions, except per unit data)
Net sales	$	1,910.5		$	2,337.4		$	6,322.6		$	6,465.5
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)	1,734.7			1,694.1			5,317.0			5,191.0
Direct operating expenses (exclusive of depreciation and amortization)	104.7			88.8			274.5			253.1
Selling, general and administrative expenses (exclusive of depreciation and amortization)	18.9			21.2			57.8			67.5
Depreciation and amortization	28.8			27.5			85.2			80.4
Total operating costs and expenses	1,887.1			1,831.6			5,734.5			5,592.0
Operating income	23.4			505.8			588.1			873.5
Other income (expense):
Interest expense and other financing costs	(10.0		)	(18.2		)	(34.8		)	(56.0		)
Interest income	0.1			—			0.3			—
Gain (loss) on derivatives, net	72.5			(168.9		)	173.0			(277.4		)
Loss on extinguishment of debt	—			—			(26.1		)	—
Other income (expense), net	—			(0.1		)	0.1			0.6
Total other income (expense)	62.6			(187.2		)	112.5			(332.8		)
Income before income tax expense	86.0			318.6			700.6			540.7
Income tax expense	—			—			—			—
Net income	$	86.0		$	318.6		$	700.6		$	540.7

Net income subsequent to initial public offering (January 23, 2013 through September 30, 2013)	$	86.0					$	622.8
Net income per common unit – basic(1)	$	0.58					$	4.22
Net income per common unit – diluted(1)	$	0.58					$	4.22

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

(1) Represents net income per common unit since closing the Partnership’s initial public offering on January 23, 2013. See Note 10 to the condensed consolidated and combined financial statements.

See accompanying notes to the condensed consolidated and combined financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL



	Common Units Issued		Limited Partner Interest			Common Unitholders			General Partner Interest		Total Partners’ Capital
	(unaudited)
	(in millions, except unit data)
Balance at December 31, 2012	—		$	980.8		$	—		$	—	$	980.8
Net income attributable to period from January 1, 2013 through January 22, 2013	—		77.8			—			—		77.8
Share-based compensation – affiliates attributable to the period from January 1, 2013 through January 22, 2013	—		0.8			—			—		0.8
Distributions to affiliates, net	—		(150.0		)	—			—		(150.0		)
Conversion of limited partner interest to common units and general partner interest	147,600,000		(909.4		)	909.4			—		—
January issuance of common units to public, net of offering costs	—		—			653.6			—		653.6
Distributions to affiliates, net	—		—			(85.1		)	—		(85.1		)
May issuance of additional common units to public, net of offering costs	13,209,236		—			393.6			—		393.6
May redemption of common units from CVR Refining Holdings, LLC	(13,209,236	)	—			(394.0		)	—		(394.0		)
Share-based compensation - Affiliates	—		—			7.5			—		7.5
Cash distributions to common unitholders - Affiliates	—		—			(345.5		)	—		(345.5		)
Cash distributions to common unitholders - Non-affiliates	—		—			(87.0		)	—		(87.0		)
Net income attributable to the period from January 23, 2013 through September 30, 2013	—		—			622.8			—		622.8
Balance at September 30, 2013	147,600,000		$	—		$	1,675.3		$	—	$	1,675.3

See accompanying notes to the condensed consolidated and combined financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2013			2012
	(unaudited)
	(in millions)
Cash flows from operating activities:
Net income	$	700.6		$	540.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	85.2			80.4
Allowance for doubtful accounts	0.6			0.6
Amortization of deferred financing costs	1.5			5.1
Amortization of original issue discount	—			0.4
Amortization of original issue premium	—			(2.6		)
Loss on disposition of assets	—			1.0
Loss on extinguishment of debt	26.1			—
Share-based compensation - affiliates	8.3			15.6
(Gain) loss on derivatives, net	(173.0		)	277.4
Current period settlements on derivative contracts	(3.9		)	(80.4		)
Changes in assets and liabilities:
Accounts receivable	(29.5		)	(99.5		)
Inventories	(147.8		)	118.6
Prepaid expenses and other current assets	(8.6		)	18.0
Insurance receivable	1.3			0.7
Other long-term assets	0.1			2.6
Accounts payable	(4.5		)	(90.5		)
Accrued expenses and other liabilities	27.3			11.1
Accrued environmental liabilities	(0.2		)	(0.1		)
Other long-term liabilities	(0.1		)	0.1
Net cash provided by operating activities	483.4			799.2
Cash flows from investing activities:
Capital expenditures	(140.8		)	(82.8		)
Proceeds from sale of assets	0.1			0.4
Net cash used in investing activities	(140.7		)	(82.4		)
Cash flows from financing activities:
Payment of capital lease obligations	(0.7		)	(0.7		)
Payments on senior secured notes	(243.4		)	—
Payment of deferred financing costs	(0.4		)	(2.0		)
Revolving debt borrowings - affiliates	11.5			—
Proceeds from January issuance of common units, net of offering costs	655.7			—
Proceeds from May issuance of common units, net of offering costs	393.6			—
Redemption of common units from CVR Refining Holdings, LLC	(394.0		)	—
Net distributions to parent	—			(637.3		)
Distributions to affiliates	(235.1		)	—
Distributions to common unitholders – affiliates	(345.5		)	—
Distributions to common unitholders – non-affiliates	(87.0		)	—
Net cash used in financing activities	(245.3		)	(640.0		)
Net increase in cash and cash equivalents	97.4			76.8
Cash and cash equivalents, beginning of period	153.1			2.7
Cash and cash equivalents, end of period	$	250.5		$	79.5

Supplemental disclosures:
Cash paid for interest net of capitalized interest of $1.7 and $3.0 in 2013 and 2012, respectively	$	32.5		$	36.5
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	$	26.3		$	17.6
Change in accounts payable related to construction in process additions	$	(11.1	)	$	(2.3	)

See accompanying notes to the condensed consolidated and combined financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2013

(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. As of September 30, 2013, Coffeyville Resources, LLC (referred to as “CRLLC”) a wholly-owned subsidiary of CVR Energy, Inc. (referred to as “CVR Energy”), owns 100% of our general partner interest and approximately 71% of our limited partner interests. As of September 30, 2013, IEP (defined below) owns approximately 82% of CVR Energy.

In preparation for the initial public offering (the "Initial Public Offering") of CVR Refining, on December 31, 2012, CRLLC contributed all of its interests in the operating subsidiaries which constitute its petroleum refining and related logistics business, as well as Coffeyville Finance Inc. ("Coffeyville Finance"), a finance subsidiary formed to serve as a co-issuer of debt securities, to a newly-formed subsidiary, CVR Refining, LLC ("Refining LLC"). The operating subsidiaries that were contributed to Refining LLC include the following entities: Wynnewood Energy Company, LLC ("WEC"); Wynnewood Refining Company, LLC ("WRC"); Coffeyville Resources Refining & Marketing, LLC ("CRRM"); Coffeyville Resources Crude Transportation, LLC ("CRCT"); Coffeyville Resources Terminal, LLC ("CRT"); and Coffeyville Resources Pipeline, LLC ("CRP"). The entities that were contributed by CRLLC to Refining LLC in connection with the Initial Public Offering are referred to herein as the "Refining Subsidiaries." CVR Refining Holdings, LLC ("CVR Refining Holdings"), a wholly-owned subsidiary of CRLLC, contributed its 100% membership interest in Refining LLC to the Partnership on December 31, 2012. In connection with the closing of the Initial Public Offering, CVR Refining Holdings and its subsidiary were issued a designated number of common units of the Partnership, which equated to approximately an 81% limited partner interest. CRLLC retained its other assets, including its ownership interests in CVR Partners, LP ("CVR Partners"), a NYSE traded manufacturer of nitrogen fertilizer, and its general partner.

The contribution of entities as discussed above by CRLLC to Refining LLC is not considered a business combination accounted for under the purchase method as it is a transfer of assets under common control and, accordingly, balances were transferred at their historical cost. The combined financial statements for the periods prior to the contribution have been prepared using the Refining Subsidiaries' historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributed to these entities.

Initial Public Offering of CVR Refining, LP

On January 23, 2013, the Partnership completed its Initial Public Offering. The Partnership sold 24,000,000 common units to the public at a price of $25.00 per common unit. Additionally, on January 30, 2013, the Partnership sold an additional 3,600,000 common units to the public at a price of $25.00 per common unit in connection with the underwriters’ exercise of their option to purchase additional common units. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."

The net proceeds to CVR Refining of approximately $653.6 million after deducting underwriting discounts and commissions and offering expenses from the Initial Public Offering have been, or will be, utilized as follows:


•	approximately $253.0 million was used to repurchase CRLLC’s 10.875% senior secured notes due 2017 (including accrued interest);


•	approximately $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarter of 2012;


•	approximately $85.1 million was distributed to CRLLC;


•	approximately $160.0 million will be used to fund certain maintenance and environmental capital expenditures through 2014; and


•	the balance of the proceeds of approximately $101.5 million has been allocated to be utilized for general corporate purposes.

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

Prior to the closing of the Initial Public Offering, the Partnership distributed approximately $150.0 million of cash on hand to CRLLC. Subsequent to the closing of the Initial Public Offering and through May 19, 2013, common units held by public security holders represented approximately 19% of all outstanding limited partner interests (this includes common units held by an affiliate of Icahn Enterprises, representing approximately 3% of all outstanding limited partner interests) and CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests.

Underwritten Offering

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

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

Subsequent to the closing of the Transactions and as of September 30, 2013, public security holders held approximately 29% of all outstanding limited partner interests (including common units held by affiliates of Icahn Enterprises, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximating 71% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, LLC, which holds a non-economic general partner interest.

The Partnership's general partner, CVR Refining GP, LLC, manages the Partnership's activities subject to the terms and conditions specified in the Partnership's partnership agreement. The Partnership's general partner is owned by CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy. 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 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 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 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.

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CVR REFINING, LP AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

CVR Energy Transaction Agreement

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the “Transaction Agreement”) with IEP Energy LLC and certain of its affiliates (collectively “IEP”). Pursuant to the Transaction Agreement, IEP offered (the “Offer”) to purchase all of the issued and outstanding shares of CVR Energy’s common stock (the “IEP Acquisition”) for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment (“CCP”) right for each share which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy was executed on or before August 18, 2013 and such transaction closed. As no sale of CVR Energy was executed by the date outlined in the Transaction Agreement, the CCPs expired on August 19, 2013.

On May 7, 2012, IEP announced that control of CVR Energy had been acquired through the Offer. As of September 30, 2013, IEP owned approximately 82% of the shares of CVR Energy.

(2) Basis of Presentation

The accompanying condensed consolidated and combined 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 and combined financial statements should be read in conjunction with the December 31, 2012 audited consolidated and combined financial statements and notes thereto included in CVR Refining’s Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 14, 2013.

Prior to the contribution of Refining LLC to the Partnership and entering into the services agreement on December 31, 2012, certain expenses incurred by CVR Energy and its affiliates were only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to CVR Refining, so that the financial statements reflect substantially all costs of doing business. Accounts and balances related to the refining and related logistics operations were based on a combination of specific identification and allocations. CVR Energy and CRLLC allocated various corporate overhead expenses based on a percentage of total refining and related logistics payroll to the total payrolls of their segments (i.e., the petroleum and fertilizer segments are comprised of CVR Refining and CVR Partners, respectively). See additional discussion in Note 15 ("Allocation of Costs").

Beginning in 2013, 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 16 ("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 and combined financial statements and related notes reflect all adjustments that are necessary to fairly present the financial position of the Partnership as of September 30, 2013 and December 31, 2012, the results of operations of the Partnership for the three and nine month periods ended September 30, 2013 and 2012, the changes in partners’ capital for the Partnership for the nine month period ended September 30, 2013 and the cash flows of the Partnership for the nine month periods ended September 30, 2013 and 2012.

The preparation of condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that reflect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from those estimates. Results of operations and cash flows are not necessarily indicative of the results that will be realized for the year ending December 31, 2013 or any other interim period.

The Partnership has omitted net income per unit for the three and nine months ended September 30, 2012, because the Partnership operated under a different capital structure prior to the closing of the Initial Public Offering, and, as a result, the per unit data would not be meaningful to investors. Per unit data for the nine months ended September 30, 2013 is calculated since the closing of the Initial Public Offering on January 23, 2013.

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(unaudited)

(3) Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. The Partnership adopted these standards as of January 1, 2013. The adoption of these standards expanded the Partnership’s condensed consolidated and combined financial statement footnote disclosures.

(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 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. CVR Refining is not responsible for payment of CVR Energy's share-based compensation and all expense amounts are recorded with a corresponding offset to increase or decrease to partners’ capital.

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 stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock). As of September 30, 2013, only grants of restricted stock units under the 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 Shares

Through the CVR Energy LTIP, shares of restricted stock and restricted stock units (collectively “restricted shares”) have been granted to employees of CVR Energy and CVR Refining. Restricted shares, when granted, were historically valued at the closing market price of CVR Energy’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the common stock. These shares generally vest over a three-year period.

The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the CVR Energy LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. The CCPs expired on August 19, 2013. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, the Partnership was allocated additional share-based compensation of approximately $6.3 million for the nine months ended September 30, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

In December 2012 and subsequent periods, restricted stock units were granted to certain employees of CVR Energy and its subsidiaries (including CVR Refining). The non-vested restricted stock units are scheduled to vest over three years, with one-third of the award vesting each year on the anniversary of the grant date, with the exception of awards granted to certain executive officers of CVR Energy that vest over one year. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of CVR Energy's common stock, plus (b) the cash value of all dividends

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(unaudited)

declared and paid per share of CVR Energy's common stock from the grant date to and including the vesting date. The awards will be remeasured at each subsequent reporting date until they vest.

Additionally, CVR Energy approved a discretionary award of up to 62,920 restricted stock units to Mr. Lipinski, CVR Energy's Chief Executive Officer and President, on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the Compensation Committee and approval of the board of directors of CVR Energy, and is conditioned on Mr. Lipinski continuing to be employed through December 31, 2013. As such, no expense related to this discretionary award was recorded during the three and nine months ended September 30, 2013. To the extent awarded, the discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award.

Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at September 30, 2013, there was approximately $6.2 million of total unrecognized compensation cost related to restricted stock units and associated dividends to be recognized over a weighted-average period of approximately 0.75 years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that occur from time to time. The unrecognized compensation expense has been determined by the number of restricted stock units and associated dividends and respective allocation percentage for individuals for whom, as of September 30, 2013, compensation expense has been allocated to the Partnership. Compensation expense recorded for the three months ended September 30, 2013 and 2012 was approximately $2.1 million and $4.9 million, respectively. Compensation expense recorded for the nine months ended September 30, 2013 and 2012 was approximately $8.3 million and $15.6 million, respectively.

Long-Term Incentive Plan – CVR Refining

In connection with the Initial Public Offering, on January 16, 2013, the board of directors of the general partner of the Partnership adopted the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIP include employees, officers, consultants and directors of CVR Refining and the general partner and their respective subsidiaries and parents. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. On August 14, 2013, the Partnership filed a Form S-8 to register the common units. As of September 30, 2013, no awards have been granted under the plan.

(5) Inventories

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

Inventories consisted of the following:



	September 30, 2013		December 31, 2012
	(in millions)
Finished goods	$	353.8	$	269.5
Raw materials and precious metals	185.6		158.1
In-process inventories	78.5		42.7
Parts and supplies	29.4		29.2
	$	647.3	$	499.5

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(6) Property, Plant, and Equipment

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



	September 30, 2013		December 31, 2012
	(in millions)
Land and improvements	$	24.8	$	24.0
Buildings	38.2		36.7
Machinery and equipment	1,739.6		1,685.6
Automotive equipment	16.0		14.3
Furniture and fixtures	6.7		6.2
Leasehold improvements	0.8		0.8
Construction in progress	116.3		46.0
	1,942.4		1,813.6
Accumulated depreciation	546.8		462.0
Total property, plant and equipment, net	$	1,395.6	$	1,351.6

Capitalized interest recognized as a reduction in interest expense for the three months ended September 30, 2013 and 2012 totaled approximately $0.7 million and $1.8 million, respectively. Capitalized interest recognized as a reduction in interest expense for the nine months ended September 30, 2013 and 2012 totaled approximately $1.7 million and $3.0 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million as of September 30, 2013 and December 31, 2012. 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, renewable identification numbers (“RINs”) and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.2 million and $1.0 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, cost of product sold excludes depreciation and amortization of approximately $3.5 million and $2.5 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 non-cash share-based compensation for CVR Energy, as discussed in Note 4 ("Share‑Based Compensation"). Direct operating expenses exclude depreciation and amortization of approximately $27.5 million and $26.4 million for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, direct operating expenses exclude depreciation and amortization of approximately $81.4 million and $77.4 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 and maintaining the corporate and administrative offices in Texas, Kansas and Oklahoma. Selling, general and administrative expenses also include allocated non-cash share-based compensation expense from CVR Energy as discussed in Note 4 (“Share-Based Compensation”). Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.1 million for each of the three months ended September 30, 2013 and 2012. For the nine months ended September 30, 2013 and 2012, selling, general and administrative expenses exclude depreciation and amortization of approximately $0.3 million and $0.5 million, respectively.

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(unaudited)

(8) Long-Term Debt

Long-term debt was as follows:



	September 30, 2013		December 31, 2012
	(in millions)
10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1.8 million as December 31, 2012	$	—	$	220.9
6.5% Senior Notes, due 2022	500.0		500.0
Intercompany credit facility	11.5		—
Capital lease obligations	50.2		51.2
Long-term debt	$	561.7	$	772.1

Senior Secured Notes

On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance (together the “Issuers”), completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the "2010 First Lien Notes") and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the "Second Lien Notes" and, together with the First Lien Notes, the "Old Notes"). The 2010 First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 15, 2011, the Issuers sold an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the "Additional First Lien Notes" and, together with the 2010 First Lien Notes, the “First Lien Notes”). The Additional First Lien Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million.

The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See further discussion below related to the tender for and subsequent redemption of all of the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. On January 23, 2013, $253.0 million of the proceeds from the Initial Public Offering were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the nine months ended September 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

2022 Senior Secured Notes

On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. The 2022 Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC’s existing domestic subsidiaries on a joint and several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, CVR Partners and Coffeyville Nitrogen Fertilizers, LLC (“CRNF”) are not guarantors.

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

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remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

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

The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Partnership incurred approximately $0.1 million and $0.4 million of debt registration costs related to the registration and exchange offering during the three and nine months ended September 30, 2013, respectively, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.

The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of September 30, 2013, the Partnership was in compliance with the covenants contained in the 2022 Notes.

At September 30, 2013, the estimated fair value of the 2022 Notes was approximately $485.6 million.These estimates of fair value are Level 2 as they were determined by quotations obtained from a broker dealer who makes a market in these and similar securities.

Amended and Restated Asset Backed (ABL) Credit Facility

On December 20, 2012, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into an amended and restated ABL credit agreement (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility, which replaced the prior ABL credit facility, is scheduled to mature on December 20, 2017. Under the amended and restated facility, the Partnership assumed CRLLC's position as borrower and CRLLC's obligations under the facility upon closing of the Initial Public Offering on January 23, 2013.

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

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commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Partnership will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.

The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of September 30, 2013.

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

As of September 30, 2013, the Partnership had availability under the Amended and Restated ABL Credit Facility of $372.9 million and had letters of credit outstanding of approximately $27.1 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of September 30, 2013.

Intercompany Credit Facility

On January 23, 2013, prior to the closing of the Initial Public Offering, the Partnership entered into a new $150.0 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 is for 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 September 30, 2013.

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 September 30, 2013, the Partnership had borrowings of $11.5 million outstanding and $138.5 million available under the intercompany credit facility.

Capital Lease Obligations

As a result of the acquisition of the Wynnewood refinery, CVR Refining acquired 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 were included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 193 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 192 months remaining and will expire in September 2029.

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(9) Partners’ Capital and Partnership Distributions

The Partnership had two types of partnership interests outstanding at September 30, 2013:


•	common units; and


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

At September 30, 2013, the Partnership had a total of 147,600,000 common units issued and outstanding, of which 104,790,764 common units were owned by CVR Refining Holdings, a wholly-owned subsidiary of CVR Energy, representing approximately 71% 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 each quarter will be determined by the board of directors of the general partner following the end of such quarter. Available cash for each quarter will generally equal Adjusted EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Adjusted EBITDA represents EBITDA (net income before interest expense, net, income tax expense, and depreciation 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) current period settlements on derivative contracts and (vii) Wynnewood acquisition transaction fees and integration expenses. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner.

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



	March 31, 2013⁽¹⁾		June 30, 2013		Total Cash Distributions Paid in 2013
	(in millions, expect per common unit amounts)
Amount paid to CVR Refining Holdings, LLC and affiliates	$	195.9	$	149.6	$	345.5
Amounts paid to non-affiliates	37.3		49.7		87.0
Total amount paid	$	233.2	$	199.3	$	432.5
Per common unit	$	1.58	$	1.35	$	2.93
Common units outstanding	147.6		147.6


(1)	The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Initial Public Offering).

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(10) Net Income per Common Unit

The net income per common unit on the Condensed Consolidated and Combined Statements of Operations is based on the net income of the Partnership after the closing of its Initial Public Offering on January 23, 2013 through September 30, 2013, since this is the amount of net income that is attributable to the Partnership’s common units.

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. No common units were issued or outstanding under the CVR Refining LTIP during the period.

The following table illustrates the Partnership's calculation of net income per common unit:



	Three Months Ended September 30, 2013		January 23, 2013 to September 30, 2013
	(in millions, except per unit data)
Net income (from the closing of the offering on January 23, 2013 to September 30, 2013)	$	86.0	$	622.8
Net income per common unit, basic	$	0.58	$	4.22
Net income per common unit, diluted	$	0.58	$	4.22
Weighted-average common units outstanding, basic	147.6		147.6
Weighted-average common units outstanding, diluted	147.6		147.6

(11) Income Taxes

CVR Refining is treated as a partnership for U.S. federal income tax purposes. Generally, each common unitholder is required to take into account its respective share of CVR Refining's income, gains, loss and deductions. The Partnership is not subject to income taxes, except for a franchise tax in the state of Texas. The income tax liability of the common unitholders is not reflected in the condensed consolidated and combined financial statements of the Partnership.

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(12) 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)
Three months ending December 31, 2013	$	0.7	$	82.7
Year Ending December 31,
2014	2.3		108.5
2015	1.4		96.7
2016	1.0		89.6
2017	0.3		88.4
Thereafter	0.3		940.7
	$	6.0	$	1,406.6

(1) This amount includes approximately $965.5 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada’s Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

CVR Refining leases various equipment and real properties under long-term operating leases expiring at various dates. For each of the three months ended September 30, 2013 and 2012, lease expense totaled approximately $0.8 million. For the nine months ended September 30, 2013 and 2012, lease expense totaled approximately $2.5 million and $2.3 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, the Partnership has long-term commitments to purchase storage capacity and pipeline transportation services.

Crude Oil Supply Agreement

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

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

Litigation

From time to time, 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

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uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying condensed consolidated and combined financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

Flood, Crude Oil Discharge and Insurance

Crude oil was discharged from CVR Refining’s Coffeyville refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In May 2008, in connection with the discharge, CVR Refining received notices of claims from sixteen private claimants under the Oil Pollution Act (“OPA”) in an aggregate amount of approximately $4.4 million (plus punitive damages). In August 2008, those claimants filed suit against CVR Refining in the United States District Court for the District of Kansas in Wichita (the “Angleton Case”). In October 2009 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. CVR Refining has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims except for one of the plaintiffs from the companion cases. The settlements did not have a material adverse effect on the condensed consolidated and combined financial statements. CVR Refining believes that the resolution of the remaining claim will not have a material adverse effect on the condensed consolidated and combined financial statements.

On October 25, 2010, CVR Refining received a letter from the United States Coast Guard on behalf of the U.S. Environmental Protection Agency (the “EPA”) seeking approximately $1.8 million in oversight cost reimbursement. CVR Refining responded by asserting defenses to the Coast Guard’s claim for oversight costs. On September 23, 2011, the United States Department of Justice (“DOJ”), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (“RMP”), the Clean Water Act (“CWA”) and the OPA. CRRM reached an agreement with the DOJ resolving its claims under the CWA and the OPA. The agreement is memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 and March 25, 2013, respectively (the “2013 Consent Decree”). On April 19, 2013, CRRM paid a civil penalty (including accrued interest) in the amount of $0.6 million for the CWA violations and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training. The parties also reached an agreement to settle DOJ’s RMP claims, which was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively, and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP settlement agreement.

CVR Refining is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, CRRM filed a lawsuit in the United States District Court for the District of Kansas against certain of its environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, CVR Refining cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the claims. CVR Refining has received $25.0 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment of the primary pollution liability policy limit.

The lawsuit with the insurance carriers under the environmental policies remains the only unsettled lawsuit with the insurance carriers related to these events.

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

CRRM, CRCT, CRT and 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.

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

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of September 30, 2013 and December 31, 2012, environmental accruals of approximately $1.8 million and $2.3 million respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.4 million and $0.7 million, respectively, are included in other current liabilities. The Partnership’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at September 30, 2013 and December 31, 2012, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million for two landfills at both September 30, 2013 and December 31, 2012. The estimated future payments for these required obligations are as follows:



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

Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

CRRM, CRCT, WRC and CRT are subject to extensive and frequently changing federal, state and local, environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, the storage, handling, use and transportation of petroleum and the characteristics and composition of gasoline and diesel fuels. The ultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.

In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, the change in control resulting from the IEP Acquisition in 2012 caused the companies to lose small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Total capital

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(unaudited)

expenditures to comply with the rule are expected to be approximately $63.0 million for CRRM and $105.0 million for WRC. As of September 30, 2013, approximately $19.1 million and $35.4 million had been spent related to these projects by CRRM and WRC, respectively.

CVR Refining is subject to the Renewable Fuel Standard ("RFS") which requires refiners to blend "renewable fuels" in with their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. On August 6, 2013 the EPA announced the final 2013 renewable fuel standard would be raised to 9.74%. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its transportation fuel or purchase RINs in lieu of blending, and in 2013, the Wynnewood refinery will be required to comply unless the Wynnewood refinery receives relief from the rule in 2013 based on the "disproportionate economic impact" of the rule on the Wynnewood refinery. From time to time, CVR Refining may purchase RINs on the open market or waiver credits for cellulosic biofuels from the EPA in order to comply with RFS. While CVR Refining cannot predict the future prices of RINs or waiver credits, the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year. The cost of RINs for the three and nine month periods ended September 30, 2012 was approximately $7.1 million and $16.5 million, respectively, and the cost of RINs for the three and nine month periods ended September 30, 2013 was approximately $57.4 million and $155.0 million, respectively. As of September 30, 2013 and December 31, 2012, CVR Refining’s biofuel blending obligation was approximately $47.5 million and $1.1 million, respectively, which was recorded in accrued expenses and other current liabilities in the Condensed Consolidated Balance Sheets. The ultimate cost of RINs for the Partnership in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the Partnership's petroleum products, as well as the fuel blending performed at the Partnership’s refineries, all of which can vary significantly from quarter to quarter.

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

In March 2004, CRRM and CRT entered into a Consent Decree (the “2004 Consent Decree”) with the EPA and the Kansas Department of Health and Environment (the “KDHE”) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.’s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.

In March 2012, CRRM entered into a "Second Consent Decree" with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA alleged industry-wide non-compliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees requiring the payment of civil penalties and the installation of air pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Partnership was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $40.0 million. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012.

WRC entered into a Consent Order with the Oklahoma Department of Environmental Quality (the "ODEQ") in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certain historic Clean Air Act compliance issues

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related to the operations of the refinery by the prior owner. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround in 2012. The remaining costs are expected to be $3.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.

From time to time, ODEQ conducts inspections of the Wynnewood refinery and identifies areas of alleged noncompliance. ODEQ routinely pursues enforcement related to the alleged noncompliance seeking civil penalties and injunctive relief, which may necessitate the installation of controls. ODEQ has advised the company that it is preparing to issue a full compliance evaluation report covering the period from 2010 through 2013. The agency has indicated that it will pursue enforcement related to the alleged noncompliance and that it expects to enter into a second Consent Order with the Company, which would necessitate the payment of a civil penalty and the implementation of injunctive relief to address the alleged noncompliance. The costs of any such enforcement action cannot be predicted at this time. However, based on our experience related to Clean Air Act enforcement and control requirements, the Company does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.

WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the “CWA Consent Order”), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged non-compliance by WRC with its Oklahoma Pollutant Discharge Elimination System permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery’s wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, the Partnership does not anticipate that the costs of any required additional controls or operational changes would be material.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended September 30, 2013 and 2012, capital expenditures were approximately $35.5 million and $7.7 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. For the nine months ended September 30, 2013 and 2012, capital expenditures were approximately $73.5 million and $18.4 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

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 above or other EHS matters which may develop in the future will not have a material adverse effect on the Partnership's business, financial condition, or results of operations.

Wynnewood Refinery Incident

On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during start up after a short outage as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there was no environmental impact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. The Partnership has completed an internal investigation of the incident and cooperated with OSHA in its investigation. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program (“SVEP”). WRC is vigorously contesting the citations and OSHA’s placement of WRC in the SVEP. Any penalties associated with OSHA’s citations are not expected to have a material adverse effect on the condensed consolidated and combined financial statements. On September 25, 2013, WRC agreed to pay a small civil penalty to settle, rather than defend claims alleged by the EPA under the Clean Air Act's general duty clause related to the boiler incident. In addition to the above, the spouses of the two employees fatally injured have filed a civil lawsuit against WRC, CVR Refining and CVR Energy in Fort Bend County, Texas. The civil suit is in its preliminary stages and it is currently too early to assess a potential outcome.

(13) 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.

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(unaudited)

ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:


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


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


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

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



	September 30, 2013
	Level 1		Level 2		Level 3		Total
	(in millions)
Location and Description
Other current assets (derivative agreements)	$	—	$	101.9	$	—	$	101.9
Other long-term assets (derivative agreements)	—		8.2		—		8.2
Total Assets	$	—	$	110.1	$	—	$	110.1



	December 31, 2012
	Level 1		Level 2			Level 3		Total
	(in millions)
Location and Description
Other long-term assets (derivative agreements)	$	—	$	0.9		$	—	$	0.9
Total Assets	$	—	$	0.9		$	—	$	0.9
Other current liabilities (derivative agreements)	—		(67.7		)	—		(67.7		)
Other current liabilities (biofuel blending obligation)	—		(1.1		)	—		(1.1		)
Total Liabilities	$	—	$	(68.8	)	$	—	$	(68.8	)

As of September 30, 2013 and December 31, 2012, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining’s derivative instruments and the 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 are valued using broker quoted market prices of similar instruments, which are considered level 2 inputs. As of September 30, 2013, CVR Refining's biofuel blending obligation was fully committed. CVR Refining had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2013.

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(14) Derivative Financial Instruments

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



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

CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions 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 settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated and Combined 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 an other current asset or an other current liability 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 September 30, 2013 was an immaterial net loss included in accrued expenses and other current liabilities. For the three months ended September 30, 2013 and 2012, CVR Refining recognized a net gain of $0.1 million and a net loss of $7.1 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated and Combined Statements of Operations. For the nine months ended September 30, 2013 and 2012, CVR Refining recognized net losses of $2.3 million and $11.0 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated and Combined Statements of Operations.

Commodity Swap

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 and Combined Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At September 30, 2013 and December 31, 2012, CVR Refining had open commodity hedging instruments consisting of 20.6 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at September 30, 2013 was a net unrealized gain of $110.1 million, of which $101.9 million is included in current assets and $8.2 million is included in non-current assets. For the three months ended September 30, 2013 and 2012, CVR Refining recognized a net gain of $72.4 million and a net loss of $161.8 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated and Combined Statements of Operations. For the nine months ended September 30, 2013 and 2012, CVR Refining recognized a net gain of $175.3 million and a net loss of $266.4 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated and Combined Statements of Operations.

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(unaudited)

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

Offsetting Assets and Liabilities

The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which 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.

The offsetting assets and liabilities for CVR Refining’s derivatives as of September 30, 2013 are recorded as current assets and non-current assets in prepaid expenses and other current assets and other long-term assets, respectively, in the Condensed Consolidated Balance Sheets as follows:



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



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

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(unaudited)

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



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



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

(15) Allocation of Costs

Prior to the contribution of Refining LLC to the Partnership and entering into the services agreement with CVR Energy on December 31, 2012, certain expenses incurred by CVR Energy and its affiliates were only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. Accordingly, the historical combined financial statements for the three and nine months ended September 30, 2012 have been prepared in accordance with SAB Topic 1-B, as more fully explained in Note 2. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. CVR Energy and CRLLC allocated general and administrative expenses to CVR Refining based on allocation methodologies that management considers reasonable and result in an allocation of the historical cost of doing business borne by CVR Energy and CRLLC on behalf of CVR Refining. These allocations may not be indicative of the cost of future operations. For the three and nine months ended September 30, 2013, amounts incurred by CVR Energy and its affiliates on behalf of Partnership have been governed and billed in accordance with the services agreement entered into between the Partnership and CVR Energy on December 31, 2012 as more fully described in Note 16 ("Related Party Transaction").

CVR Refining's Combined Statements of Operations for the three and nine months ended September 30, 2012 reflect all of the expenses that CRLLC and CVR Energy incurred on CVR Refining's behalf. CVR Refining's financial statements therefore include certain expenses incurred by CVR Energy and CRLLC which may include, but are not necessarily limited to, the following:

• Officer and employee salaries and share-based compensation;

• Rent or depreciation;

• Advertising;

• Accounting, tax, legal and information technology services;

• Other selling, general and administrative expenses;

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• Costs for defined contribution plans, medical and other employee benefits; and

• Financing costs, including interest and losses on extinguishment of debt.

Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining as governed by percentages determined by management to be reasonable and in line with the nature of an individual's roles and responsibilities. Allocations related to share-based compensation are more fully described in Note 4 ("Share‑Based Compensation"). Cost allocations, either allocated or billed, of $3.0 million and $14.4 million were included in direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization), respectively, for the three months ended September 30, 2012. Cost allocations, either allocated or billed, of $8.8 million and $48.9 million were included in direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization), respectively, for the nine months ended September 30, 2012.

(16) Related Party Transactions

In connection with the formation of CVR Refining in September 2012 and the Partnership’s Initial Public Offering in January 2013, CVR Refining and CRRM entered into certain agreements with CVR Energy and its subsidiaries that govern the business relations among CVR Refining, its general partner and CRRM on the one hand, and CVR Energy and its subsidiaries, on the other hand. CRRM has previously entered into other agreements with CVR Partners and its subsidiary. Certain of the agreements described below were amended and restated on April 13, 2011 in connection with the initial public offering of CVR Partners; the agreements are described as in effect at September 30, 2013. Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable, prepaid expenses and other current assets, and other long-term 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, 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 entered into a feedstock and shared services agreement with CRNF under which the two parties provide feedstock 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 the obligation to transfer excess hydrogen to one another. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining. 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 September 30, 2013 and 2012, the net sales generated from the sale of hydrogen to CRNF were approximately $0.3 million and $0.1 million, respectively. For the nine months ended September 30, 2013 and 2012, the net sales generated from the sale of hydrogen to CRNF were approximately $0.6 million and $0.2 million, respectively. For the three months ended September 30, 2013 and 2012, CVR Refining also recognized $0.8 million and $0.3 million of cost of product sold (exclusive of depreciation and amortization) related to the purchase of excess hydrogen from the nitrogen fertilizer facility, respectively. For the nine months ended September 30, 2013 and 2012, CVR Refining also recognized $4.7 million and $6.0 million of cost of product sold (exclusive of depreciation and amortization) related to the purchase of excess hydrogen from the nitrogen fertilizer facility, respectively. At September 30, 2013 and December 31, 2012, there was approximately $0.8 million and $0.2 million, respectively, of payables included in accounts payable on the Condensed Consolidated Balance Sheets associated with unpaid balances related to hydrogen.

The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net reimbursed or (paid) direct operating expenses recorded during the three months ended September 30, 2013 and 2012 were approximately $(8,000) and $(2,000), respectively, related to high-pressure steam. Net reimbursed or (paid) direct operating expenses recorded during the nine months ended September 30, 2013 and 2012 were approximately $10,000 and $42,000, respectively, related to high-pressure steam. Reimbursements or paid amounts for each of the years on a gross basis were nominal.

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NOTES TO THE CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

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 September 30, 2013 and 2012, were approximately $0.1 million and $0.4 million, respectively. Direct operating expenses associated with nitrogen purchased by CRRM from CRNF for the nine months ended September 30, 2013 and 2012, were approximately $0.4 million and $1.3 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 the three months ended September 30, 2013 and 2012, CRRM recognized approximately $0 and $0.1 million, respectively, of direct operating expenses generated from the purchase of tail gas from CRNF. For the nine months ended September 30, 2013 and 2012, CRRM recognized approximately $0.1 million and $0.2 million, respectively of direct operating expenses generated from the purchase of tail gas from CRNF.

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 has agreed to pay CRRM the cost of installing the pipe over the next three years and in the fourth year provide an additional 15% to cover the cost of capital. At September 30, 2013 and December 31, 2012, an asset of approximately $0.4 million and $0.5 million, respectively, was included in other current assets and approximately $0.1 million and $0.4 million, respectively, was included in other non-current assets with an offset liability of approximately $0.2 million in other current liabilities and approximately $1.2 million and $1.3 million, respectively, in other non-current liabilities in the Condensed Consolidated Balance Sheets.

CRNF also provided finished product tank capacity to CRRM under the agreement. Approximately $0.1 million and $0 was incurred by CRRM for the use of tank capacity for the three months ended September 30, 2013 and 2012. Approximately $0.3 million and $0.1 million, respectively, was incurred by CRRM for the use of tank capacity for the nine months ended September 30, 2013 and 2012, respectively. This expense was recorded as direct operating expenses.

The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.

At September 30, 2013 and December 31, 2012, payables of $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 September 30, 2013 and December 31, 2012, receivables of $0.8 million and $0.4 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 entered into 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,

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September 30, 2013

(unaudited)

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.

The agreement has an initial term of 20 years and will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.

Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $1.7 million and $2.4 million for the three months ended September 30, 2013 and 2012, respectively. Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $7.0 million and $7.3 million for the nine months ended September 30, 2013 and 2012, respectively. Receivables of $0.3 million and $0.6 million related to the coke supply agreement were included in accounts receivable on the Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012, respectively.

Terminal Operating and Lease Agreement

On May 4, 2012, CRT entered into an operating and lease agreement with CRNF, under which it leases premises to CRNF located at Phillipsburg, Kansas, which CRNF uses as a UAN terminal. The initial term of the agreement will expire in May 2032, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, this agreement will automatically renew for successive five-year terms, provided that CRNF may terminate the agreement during any renewal term with at least 180 days written notice. CRNF will pay CRT $1.00 per year for rent, $4.00 per ton of UAN placed into the terminal and $4.00 per ton of UAN taken out of the terminal. For the three and nine months ended September 30, 2013, revenue related to the terminal operating and lease agreement totaled approximately $28,000 and $83,000, respectively. For each of the three and nine months ended September 30, 2012, revenue totaled approximately $12,000.

Lease Agreement

CRRM entered into a lease agreement with CRNF under which CRNF leases certain office and laboratory space. The initial term of the lease will expire in October 2017, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, CRNF has the option to renew the lease agreement for up to five additional one-year periods by providing CRRM with notice of renewal at least 60 days prior to the expiration of the then existing term. For the three months ended September 30, 2013 and 2012, amounts received related to the use of the office and laboratory space totaled approximately $27,000 and $26,000 For each of the nine months ended September 30, 2013 and 2012, amounts received related to the use of the office and laboratory space totaled approximately $0.1 million.

Environmental Agreement

CRRM entered into an environmental agreement with CRNF which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville, Kansas refinery and the nitrogen fertilizer plant. Generally, both CRRM and CRNF have agreed to indemnify and defend each other and each other's affiliates against liabilities associated with certain hazardous materials and violations of environmental laws that are a result of or caused by the indemnifying party's actions or business operations. This obligation extends to indemnification for liabilities arising out of off-site disposal of certain hazardous materials. Indemnification obligations of the parties will be reduced by applicable amounts recovered by an indemnified party from third parties or from insurance coverage.

The agreement provides for indemnification in the case of contamination or releases of hazardous materials that were present but unknown at the time the agreement was entered into to the extent such contamination or releases were identified in reasonable detail through October 2012. The agreement further provides for indemnification in the case of contamination or releases which occur subsequent to the execution of the agreement.

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NOTES TO THE CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(unaudited)

The term of the agreement is for at least 20 years, or for so long as the feedstock and shared services agreement is in force, whichever is longer.

Services Agreement

On December 31, 2012, CVR Refining entered into a services agreement with CVR Energy. 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. Under this agreement, the Partnership's general partner has engaged CVR Energy to conduct a substantial portion of its day-to-day business operations. CVR Energy provides CVR Refining with the following services under the agreement, among others:


•	services from CVR Energy's employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall serve the Partnership on a shared, part-time basis only, unless the Partnership and CVR Energy agree otherwise;


•	administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs;


•	management of the Partnership's property and the property of its operating subsidiaries in the ordinary course of business;


•	recommendations on capital raising activities to the board of directors of the Partnership's general partner, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions;


•	managing or overseeing litigation and administrative or regulatory proceedings, establishing appropriate insurance policies for the Partnership and providing safety and environmental advice;


•	recommending the payment of distributions; and


•	managing or providing advice for other projects, including acquisitions, as may be agreed by CVR Energy and the Partnership's general partner from time to time.

As payment for services provided under the agreement, the Partnership, its general partner or subsidiaries must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other than administrative personnel, who provide the Partnership services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide the Partnership services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percentage of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges.

Either CVR Energy or the Partnership's general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days' notice. Beginning in January 2014, either CVR Energy or the Partnership's general partner may terminate the agreement upon at least 180 days' notice, but not more than one year's notice. Furthermore, the Partnership's general partner may terminate the agreement immediately if CVR Energy becomes bankrupt or dissolves or commences liquidation or winding-up procedures.

In order to facilitate the carrying out of services under the agreement, CVR Refining and CVR Energy have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another's intellectual property under certain circumstances.

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The agreement also contains an indemnity provision whereby the Partnership, its general partner, and its subsidiaries, as indemnifying parties, agree to indemnify CVR Energy and its affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by CVR Energy or other misconduct on its part, as provided in the agreement. The agreement contains a provision stating that CVR Energy is an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by CVR Energy, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from CVR Energy or certain affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement, or fraudulent or dishonest acts.

Net amounts incurred under the services agreement for the three months ended September 30, 2013 were approximately $22.0 million. Of these charges approximately $15.4 million were included in selling, general and administrative expenses (exclusive of depreciation and amortization). In addition, $6.6 million were included in direct operating expenses (exclusive of depreciation and amortization). Net amounts incurred under the services agreement for the nine months ended September 30, 2013 were approximately $64.5 million. Of these charges approximately $45.4 million were included in selling, general and administrative expenses (exclusive of depreciation and amortization). In addition, $19.1 million were included in direct operating expenses (exclusive of depreciation and amortization). At September 30, 2013, payables of $12.6 million were included in accounts payable on the Condensed Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement. See Note 15 ("Allocation of Costs") for costs allocated to CVR Refining for the three and nine months ended September 30, 2012 prior to this services agreement going into effect on December 31, 2012.

Limited Partnership Agreement

In connection with the Initial Public Offering, CVR Refining GP and CVR Refining Holdings entered into the first amended and restated agreement of limited partnership of the Partnership, dated January 23, 2013.

The Partnership's general partner manages the Partnership's operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. CVR Refining Holdings has the right to select the directors of the general partner. Actions by the general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the general partner and not by its board of directors. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to re-election on a regular basis by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership's business.

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 and nine months ended September 30, 2013, approximately $0.1 million and $0.2 million, respectively, was incurred under the partnership agreement.

Intercompany Credit Facility

On January 23, 2013, prior to the closing of the Initial Public Offering, the Partnership entered into a $150.0 million intercompany credit facility, with CRLLC as the lender, to be used to fund growth capital expenditures. The intercompany credit facility is for a term of six years and bears interest at a rate of LIBOR plus 3% per annum. As of September 30, 2013, the Partnership had borrowings of $11.5 million outstanding. See Note 8 ("Long-Term Debt") for additional discussion of the intercompany credit facility.

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September 30, 2013

(unaudited)

Insight Portfolio Group

Insight Portfolio Group LLC (“Insight Portfolio Group”) is an entity formed by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group. 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.

International Truck Purchase

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

(17) Subsequent Events

Distribution

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

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

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated and combined financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission (“SEC”) on March 14, 2013. Results of operations for the three and nine months ended September 30, 2013 are not necessarily indicative of results to be attained for any other period.

Forward-Looking Statements

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


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


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


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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward‑looking statements we make in this Report, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and 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 the 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 ability to purchase gasoline and diesel RINs on a timely and cost effective basis;


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


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

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•	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;


•	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 and conflicts of interest they face operating each of CVR Partners, CVR Refining and CVR Energy;


•	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 significant 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 rely on in connection with the NYSE corporate governance requirements;


•	risks relating to evaluations of internal controls required by Section 404 of the Sarbanes-Oxley Act of 2002;


•	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; and


•	changes in our treatment as a partnership for U.S. federal income tax purposes.

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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 as may be 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 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd medium complexity crude oil refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and located at throughput terminals on Magellan and NuStar refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of owned and leased pipeline) that transports crude oil to our Coffeyville refinery from our Broome Station tank farm located near Caney, Kansas and (4) over 6.0 million barrels of crude oil storage.

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. The early June 2012 reversal of the Seaway Pipeline that now flows from Cushing to the U.S. Gulf Coast has eliminated our ability to source foreign waterborne crude oil, as well as deep water U.S. Gulf of Mexico produced sweet and sour crude oil grades. In addition to rack sales (sales which are made at terminals into third party tanker trucks), 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 tank farm. We maintain capacity on the Spearhead and Keystone pipelines from Canada 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 and sweet synthetics. Crude oil is supplied to our Wynnewood refinery through two third-party pipelines operated by Sunoco Pipeline and Excel 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. We expect to spend approximately $60.0 million on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. As of September 30, 2013, approximately $16.3 million has been spent on the Wynnewood hydrocracker project. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the third quarter of 2013 was $1.25 per barrel compared to $4.38 per barrel in the third quarter of 2012.

Our History

We were formed by CVR Energy in September 2012 in order to own and operate petroleum and auxiliary businesses as a limited partnership. In preparation for our Initial Public Offering, CRLLC contributed its wholly-owned subsidiaries and logistics assets described above to Refining LLC in October 2012, and CVR Refining Holdings, a subsidiary of CRLLC, contributed Refining LLC to us in December 2012.

Our Initial Public Offering

On January 23, 2013, we completed our Initial Public Offering of 24,000,000 common units to the public priced at $25.00 per unit. Additionally, on January 30, 2013, we sold an additional 3,600,000 common units to the public priced at $25.00 per unit in connection with the exercise of the underwriters’ option to purchase additional common units. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol “CVRR.” Following the closing of the Initial Public Offering and through May 19, 2013, common units held by public security holders represented approximately 19% of all outstanding limited partner interests (including common units held by an affiliate of Icahn Enterprises, representing approximately 3% of all outstanding limited partner interests), while CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests in addition to owning 100% of CVR Refining GP, LLC, our general partner.

The net proceeds to us from the Initial Public Offering were approximately $653.6 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $253.0 million of the net proceeds were used to redeem all of

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the outstanding Second Lien Notes, $160.0 million will be used to fund certain maintenance and environmental capital expenditures through 2014, $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery in the fourth quarter of 2012, $85.1 million was distributed to CRLLC and the remaining proceeds have been or will be used for general corporate purposes. Prior to the closing of the Initial Public Offering, we distributed approximately $150.0 million of cash on hand to CRLLC.

Underwritten Offering

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

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

We utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters’ option) to redeem 13,209,236 common units from CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy. We did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC. In connection with the Underwritten Offering, we incurred approximately $0.4 million of offering expenses.

CVR Energy Transaction Agreement

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the “Transaction Agreement”) with IEP Energy LLC and certain of its affiliates (collectively “IEP”). Pursuant to the Transaction Agreement, IEP offered (the “Offer”) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment (“CCP”) right for each share which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy was executed on or before August 18, 2013 and such transaction closed. As no sale of CVR Energy was executed by the date outlined in the Transaction Agreement, the CCPs expired on August 19, 2013.

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

Major Influences on Results of Operations

Our earnings and cash flows from our petroleum business are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire 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

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

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

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

In order to assess 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 crude oil 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,

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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.

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

Because crude oil and other feedstocks and refined products are commodities, 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 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 a two-phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. We completed a turnaround at our Wynnewood refinery in December 2012. The next turnaround for the Wynnewood refinery is scheduled to begin in late 2016.

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. 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) an easement agreement; (v) an environmental agreement and (vi) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners. 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.

In connection with our Initial Public Offering, we entered into a number of agreements with CVR Energy, including (i) a $150.0 million 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

In August 2012, CRRM and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended. Under the agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014. Following the initial term, the Vitol Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 180 days prior to the expiration of the initial term or any renewal term.

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Factors Affecting Comparability

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Fluid Catalytic Cracking Unit (“FCCU”) Outage

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

New and Refinanced Indebtedness

Notes. In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, Inc. (“Coffeyville Finance”), issued $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Old Notes”). As the Old Notes were incurred for the benefit of our operations, all debt and associated costs have been allocated to us in our condensed consolidated and combined financial statements.

In December 2010, CRLLC voluntarily redeemed $27.5 million of the First Lien Notes. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million of First Lien Notes to partially fund the acquisition of the Wynnewood refinery. In connection with the acquisition of the Wynnewood refinery, in November 2011, CRLLC received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of $200.0 million of the First Lien Notes.

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

On January 23, 2013, $253.0 million of the proceeds from our Initial Public Offering were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the nine months ended September 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

Share‑Based Compensation

Certain of our employees and employees of CVR Energy who perform services for us participate in equity compensation plans of CVR Energy and its affiliates. Accordingly, we have been allocated and have recorded share-based compensation expense related to these plans. Through CVR Energy’s Long-Term Incentive Plan (the “CVR Energy LTIP”), equity compensation awards may be awarded to CVR Energy’s employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by affiliates of Icahn Enterprises and the related change of control described above, restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock.

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or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, we were allocated additional share-based compensation of $6.3 million for the nine months ended September 30, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. For the three months ended September 30, 2013 and 2012, we were allocated compensation expense of $2.1 million and $4.9 million, respectively, related to non-vested share-based compensation awards issued through the CVR Energy LTIP. For the nine months ended September 30, 2013 and 2012, we were allocated compensation expense of $8.3 million and $15.6 million, respectively, related to non-vested share-based compensation awards issued through the CVR Energy LTIP.

Distributions to CVR Refining Unitholders

The current policy of the board of directors of our general partner is to distribute all of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter and will generally equal Adjusted EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Actual distributions are set by the board of directors of our general partner. The board of directors of our general partner may modify the cash distribution policy at any time, and the partnership agreement does not require us to make distributions at all.

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



	March 31, 2013⁽¹⁾		June 30, 2013		Total Cash Distributions Paid in 2013
	($ in millions, expect per common unit amounts)
Amount paid to CVR Refining Holdings, LLC and affiliates	$	195.9	$	149.6	$	345.5
Amounts paid to non-affiliates	37.3		49.7		87.0
Total amount paid	$	233.2	$	199.3	$	432.5
Per common unit	$	1.58	$	1.35	$	2.93
Common units outstanding	147.6		147.6


(1)	The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Initial Public Offering).

Commodity Swaps

Turnaround Projects

The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery incurred costs of approximately $21.2 million

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for the nine months ended September 30, 2012 associated with the 2011/2012 turnaround. The Wynnewood refinery incurred turnaround costs of approximately $13.4 million for the three and nine months ended September 30, 2012 related to the turnaround, which was completed in the fourth quarter of 2012.

Wynnewood Transaction Fees and Integration Expenses

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

Publicly Traded Partnership Expenses

We expect our general and administrative expenses will increase due to the costs of operating as a publicly traded partnership, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, will approximate $5.0 million per year, excluding the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing.

Results of Operations

The following tables summarize the financial data and key operating statistics for CVR Refining and our subsidiaries for the three and nine months ended September 30, 2013 and 2012. The discussion of our results of operations for the three and nine months ended September 30, 2012 is based on the historical operations of the petroleum refining and related logistics business of CVR Energy, including the operations of both the Coffeyville and Wynnewood refineries, each of which was contributed to us on December 31, 2012. The following data should be read in conjunction with our condensed consolidated and combined financial statements and the notes thereto included elsewhere in this Report. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” except for the balance sheet data as of December 31, 2012, is unaudited.

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 “—Factors Affecting Our 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Consolidated Statement of Operations Data:
Net sales	$	1,910.5		$	2,337.4		$	6,322.6		$	6,465.5
Cost of product sold(1)	1,734.7			1,694.1			5,317.0			5,191.0
Direct operating expenses(1)(2)	104.7			77.7			274.5			218.5
Major scheduled turnaround expenses	—			11.1			—			34.6
Selling, general and administrative expenses(1)(2)	18.9			21.2			57.8			67.5
Depreciation and amortization	28.8			27.5			85.2			80.4
Operating income	23.4			505.8			588.1			873.5
Interest expense and other financing costs	(10.0		)	(18.2		)	(34.8		)	(56.0		)
Interest income	0.1			—			0.3			—
Gain (loss) on derivatives, net	72.5			(168.9		)	173.0			(277.4		)
Loss on extinguishment of debt	—			—			(26.1		)	—
Other income (expense), net	—			(0.1		)	0.1			0.6
Income before income tax expense	86.0			318.6			700.6			540.7
Income tax expense	—			—			—			—
Net income	$	86.0		$	318.6		$	700.6		$	540.7
Gross profit(4)	$	42.3		$	527.0		$	645.9		$	941.0
Refining margin(5)	$	175.8		$	643.3		$	1,005.6		$	1,274.5
Adjusted EBITDA(6)	$	33.9		$	447.1		$	594.5		$	988.9
Available cash for distribution(7)	$	44.0



	As of September 30, 2013		As of December 31, 2012
			(audited)
	(in millions)
Balance Sheet Data
Cash and cash equivalents	$	250.5	$	153.1
Working capital	819.0		382.7
Total assets	2,686.5		2,258.5
Total debt, including current portion	562.9		773.2
Total partners’ capital	1,675.3		980.8



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	16.2		$	413.7		$	483.4		$	799.2
Investing activities	(60.7		)	(20.2		)	(140.7		)	(82.4		)
Financing activities	(188.3		)	(343.4		)	(245.3		)	(640.0		)
Net cash flow	$	(232.8	)	$	50.1		$	97.4		$	76.8
Other Financial Data
Capital expenditures for property, plant and equipment	$	60.7		$	20.2		$	140.8		$	82.8

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Refining margin(5)	$	11.89	$	36.31	$	20.15	$	26.34
Gross profit(4)	$	2.86	$	29.75	$	12.94	$	19.45
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(3)	$	7.08	$	5.02	$	5.50	$	5.23
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(8)	$	6.92	$	4.81	$	5.29	$	4.75
Barrels sold (barrels per day)(8)	164,431		200,683		190,055		194,638



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

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

____________


(1)	Our cost of product sold, direct operating expenses and selling, general and administrative expenses for the three and nine months ended September 30, 2013 and 2012 are shown exclusive of depreciation and amortization, which is comprised of the following components:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Depreciation and amortization excluded from cost of product sold	$	1.2	$	1.0	$	3.5	$	2.5
Depreciation and amortization excluded from direct operating expenses	27.5		26.4		81.4		77.4
Depreciation and amortization excluded from selling, general and administrative expenses	0.1		0.1		0.3		0.5
Total depreciation and amortization	$	28.8	$	27.5	$	85.2	$	80.4

(2)

Our direct operating expenses and selling, general and administrative expenses for the three and nine months ended September 30, 2013 and 2012 include a charge related to CVR Energy’s share-based compensation expense allocated to us by CVR Energy for financial reporting purposes in accordance with ASC 718. We are not responsible for the payment of cash related to any share-based compensation allocated to us by CVR Energy. See “—Critical Accounting Policies—Shared-Based Compensation” in our Annual Report on Form 10-K for the year-ended December 31, 2012 for more information. The charges for allocated share-based compensation were:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Direct operating expenses	$	0.4	$	0.4	$	1.2	$	1.2
Selling, general and administrative expenses	1.7		4.5		7.1		14.4
Total	$	2.1	$	4.9	$	8.3	$	15.6

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(3)	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.

(4)

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

(5)

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 that 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 and Combined 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 barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.

(6)

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) Wynnewood acquisition transaction fees and integration expenses. 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, evaluate our ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance. EBTIDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the three and nine months ended September 30, 2013 and 2012:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Net income	$	86.0		$	318.6		$	700.6		$	540.7
Add:
Interest expense and other financing costs, net of interest income	9.9			18.2			34.5			56.0
Income tax expense	—			—			—			—
Depreciation and amortization	28.8			27.5			85.2			80.4
EBITDA	124.7			364.3			820.3			677.1
Add:
FIFO impacts (favorable) unfavorable(a)	(54.3		)	(50.9		)	(83.3		)	54.3
Share-based compensation, non-cash	2.1			4.9			8.3			15.6
Loss on extinguishment of debt	—			—			26.1			—
Major scheduled turnaround expenses	—			11.1			—			34.6
(Gain) loss on derivatives, net	(72.5		)	168.9			(173.0		)	277.4
Current period settlements on derivative contracts(b)	33.9			(53.2		)	(3.9		)	(80.4		)
Wynnewood acquisition transaction fees and integration expenses	—			2.0			—			10.3
Adjusted EBITDA	$	33.9		$	447.1		$	594.5		$	988.9

(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.


(b)	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.

(7)

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 distributions may be increased by 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 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 as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure.

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	Three Months Ended September 30, 2013
	(in millions, except per unit data)
Reconciliation of Adjusted EBITDA to Available cash for distribution	$	33.9
Adjusted EBITDA
Adjustments:
Less:
Cash needs for debt service	(10.0		)
Reserves for environmental and maintenance capital expenditures	(31.2		)
Reserves for future turnarounds	(8.7		)
Add:
Release of excess cash	60.0
Available cash for distribution	$	44.0
Available cash for distribution, per unit	$	0.30
Common units outstanding (in thousands)	147,600


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

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



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



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

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



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

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

Net Sales. Net sales were $1,910.5 million for the three months ended September 30, 2013 compared to $2,337.4 million for the three months ended September 30, 2012. The decrease of $426.9 million was the result of lower overall sales volume due to the FCCU outage at the Coffeyville refinery and lower product prices. Our average sales price per gallon for the three months ended September 30, 2013 for gasoline of $2.89 decreased by approximately 4.6% as compared to the three months ended September 30, 2012. Our average sales price per gallon for the three months ended September 30, 2013 for distillates of $3.07 decreased by approximately 2.5% as compared to the same period in 2012.



	Three Months Ended September 30, 2013					Three Months Ended September 30, 2012					Total Variance
	Volume(1)	$ per barrel		Sales $(2)		Volume(1)	$ per barrel		Sales $(2)		Volume(1)		Sales $(2)			Price Variance			Volume Variance
																(in millions)
Gasoline	7.7	$	121.55	$	935.3	9.6	$	127.27	$	1,220.5	(1.9	)	$	(285.2	)	$	(44.1	)	$	(241.1	)
Distillate	6.5	$	128.98	$	840.5	7.6	$	132.18	$	1,001.6	(1.1	)	$	(161.1	)	$	(20.9	)	$	(140.2	)

(1) Barrels in millions

(2) Sales dollars in millions

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs, transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $1,734.7 million for the three months ended September 30, 2013 compared to $1,694.1 million for the three months ended September 30, 2012. Cost of products sold increased by $40.6 million despite the decrease in our sales volume of approximately 16%. The cost increase was primarily due to an increase in our RINS cost. Our consumed crude cost for the quarter ended September 30, 2013 as compared to the same period last year was slightly lower. The consumed crude cost reduction was due to a decline in crude oil throughputs by 16.5% as a result of our FCCU outage at the Coffeyville refinery this quarter, largely offset by a rise in market prices of crude oil and a narrowing of our consumed crude oil discount to WTI for this quarter as compared to the same quarter last year. Our consumed crude oil discount to WTI for the third quarter of 2013 was $1.25 per barrel as compared to $4.38 in the third quarter of 2012.

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

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

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primarily related to a decrease in integration costs related to the acquisition of the Wynnewood refinery and lower allocated share-based compensation expenses from CVR Energy, partially offset by increases in personnel costs and outside services.

Operating Income. Operating income was $23.4 million for the three months ended September 30, 2013 as compared to operating income of $505.8 million for the three months ended September 30, 2012. This decrease of $482.4 million was the result of a decrease in refining margin ($467.5 million), an increase in direct operating expenses ($15.9 million) and an increase in depreciation and amortization ($1.3 million), partially offset by a decrease in selling, general and administrative expenses ($2.3 million).

Interest Expense. Interest expense for the three months ended September 30, 2013 was $10.0 million as compared to interest expense of $18.2 million for the three months ended September 30, 2012. This $8.2 million decrease resulted primarily from lower interest expense on the outstanding 2022 Notes for the three months ended September 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the three months ended September 30, 2012.

Gain (loss) on Derivatives, net. For the three months ended September 30, 2013, we recorded a $72.5 million net gain on derivatives compared to a $168.9 million net loss on derivatives for the three months ended September 30, 2012. The change was primarily due to changes in crack spreads during the periods. We entered into several over-the-counter commodity swaps to fix the margin on a portion of our future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014.

Nine months ended September 30, 2013 Compared to the Nine months ended September 30, 2012

Net Sales. Net sales were $6,322.6 million for the nine months ended September 30, 2013 compared to $6,465.5 million for the nine months ended September 30, 2012. The decrease of $142.9 million was the result of slightly lower overall sales volumes and lower product prices. Our average sales price per gallon for the nine months ended September 30, 2013 for gasoline of $2.86 decreased by approximately 2.4% as compared to the nine months ended September 30, 2012. Our average sales price per gallon for the nine months ended September 30, 2013 for distillates of $3.04 decreased by approximately 1.0% as compared to the same period in 2012.



	Nine Months Ended September 30, 2013					Nine Months Ended September 30, 2012					Total Variance
	Volume(1)	$ per barrel		Sales $(2)		Volume(1)	$ per barrel		Sales $(2)		Volume(1)		Sales $(2)			Price Variance			Volume Variance
																(in millions)
Gasoline	26.5	$	120.11	$	3,182.8	27.4	$	123.18	$	3,380.3	(0.9	)	$	(197.5	)	$	(81.4	)	$	(116.1	)
Distillate	21.8	$	127.83	$	2,790.4	21.4	$	128.98	$	2,760.1	0.4		$	30.3		$	(25.2	)	$	55.5

(1) Barrels in millions

(2) Sales dollars in millions

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs, transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $5,317.0 million for the nine months ended September 30, 2013 compared to $5,191.0 million for the nine months ended September 30, 2012. The increase of $126.0 million was primarily the result of an increase in the cost of RINs and higher crude oil prices, partially offset by slightly lower sales volumes. Our average cost per barrel of crude oil consumed for the nine months ended September 30, 2013 was $94.52 compared to $92.76 for the comparable period of 2012, an increase of approximately 1.9%. Sales volume of refined fuels decreased by approximately 0.7%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the nine months ended September 30, 2013, we had an favorable FIFO inventory impact of $83.3 million compared to an unfavorable FIFO inventory impact of $54.3 million for the comparable period of 2012.

Refining margin per barrel of crude oil throughput decreased from $26.34 for the nine months ended September 30, 2012 to $20.15 for the nine months ended September 30, 2013. Refining margin adjusted for FIFO impact was $18.48 per crude oil throughput barrel for the nine months ended September 30, 2013, as compared to $27.46 per crude oil throughput barrel for the nine months ended September 30, 2012. Gross profit per barrel decreased to $12.94 for the nine months ended September 30, 2013

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as compared to gross profit per barrel of $19.45 in the equivalent period in 2012. The decrease in refining margin and gross margin per barrel is primarily due to a decrease in sales prices of gasoline and distillates, an increase in RINs costs and an increase in our per barrel cost of consumed crude oil. Consumed crude oil costs increased due to a 2.1% decrease in WTI for the nine months ended September 30, 2013 over the nine months ended September 30, 2012.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) 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 (exclusive of depreciation and amortization) were $274.5 million for the nine months ended September 30, 2013 compared to direct operating expenses and major scheduled turnaround expenses of $253.1 million for the nine months ended September 30, 2012. The increase of $21.4 million was primarily the result of the increase in expenses associated with repairs and maintenance ($35.7 million), labor ($9.3 million), energy and utility costs ($9.0 million) and outside services ($3.7 million). These increases were partially offset by a decrease in major scheduled turnaround performed in the prior year ($34.6 million). Our Coffeyville refinery completed the second phase of its planned turnaround in March 2012. Direct operating expenses per barrel of crude oil throughput for the nine months ended September 30, 2013 increased to $5.50 per barrel as compared to $5.23 per barrel for the nine months ended September 30, 2012. The increase in the direct operating expenses per barrel of crude oil throughput is a function of the higher overall expenses.

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 $57.8 million for the nine months ended September 30, 2013 as compared to $67.5 million for the nine months ended September 30, 2012. The decrease of $9.7 million over the comparable period was primarily the result of a decrease in allocated share-based compensation expenses from CVR Energy, primarily related to the modification of CVR Energy’s restricted shares to liability-classified restricted stock unit awards during the nine months ended September 30, 2012 and a decrease in integration costs related to the acquisition of the Wynnewood refinery, partially offset by increases in allocated outside service costs and personnel expenses.

Operating Income. Operating income was $588.1 million for the nine months ended September 30, 2013 as compared to operating income of $873.5 million for the nine months ended September 30, 2012. This decrease of $285.4 million was the result of a decrease in the refining margin ($268.9 million) and increases in direct operating expense ($21.4 million) and depreciation and amortization ($4.8 million), partially offset by a decrease in selling, general and administrative expense ($9.7 million).

Interest Expense. Interest expense for the nine months ended September 30, 2013 was $34.8 million as compared to interest expense of $56.0 million for the nine months ended September 30, 2012. The decrease of $21.2 million resulted primarily from lower interest expense on the outstanding 2022 Notes for the nine months ended September 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the nine months ended September 30, 2012.

Gain (loss) on Derivatives, net. For the nine months ended September 30, 2013, we recorded a $173.0 million net gain on derivatives compared to a $277.4 million net loss on derivatives for the nine months ended September 30, 2012. The change was primarily due to changes in crack spreads during the periods. We entered into several over-the-counter commodity swaps to fix the margin on a portion of our future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014.

Loss on Extinguishment of Debt. For the nine months ended September 30, 2013, we incurred a $26.1 million loss on extinguishment of debt. The loss on the extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid, the write-off of previously deferred financing costs and the write-off of the unamortized original issuance discount.

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. Prior to December 31, 2012, CRLLC historically used a centralized approach to cash management and provided cash as needed to support our operations and retained excess cash earned by our operations. Beginning January 1, 2013, we operate with an independent capital structure.

Our liquidity was enhanced during the first quarter of 2013 by the proceeds from our Initial Public Offering of approximately $653.6 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $253.0 million of the net proceeds were used to redeem all of the outstanding Second Lien Notes, $160.0 million will be used to fund certain

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maintenance and environmental capital expenditures through 2014, $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery in the fourth quarter of 2012, $85.1 million was distributed to CRLLC and the remaining proceeds have been or will be used for general corporate purposes. Prior to the closing of the Initial Public Offering, we distributed approximately $150.0 million of cash on hand to CRLLC.

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 $150.0 million senior unsecured revolving 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 September 30, 2013 we had cash and cash equivalents of $250.5 million. Working capital at September 30, 2013 was $819.0 million, consisting of $1,265.8 million in current assets and $446.8 million in current liabilities. Working capital at December 31, 2012 was $382.7 million, consisting of $885.4 million in current assets and $502.7 million in current liabilities. As of October 29, 2013, we had cash and cash equivalents of $221.6 million.

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 swingline loans and 90% of the total facility commitment for letters of credit. The intercompany credit facility provides us with borrowing availability of up to $150.0 million. The intercompany credit facility is scheduled to mature on January 29, 2019.

As of September 30, 2013, we had $372.9 million available under the Amended and Restated ABL Credit Facility and $138.5 million available under the intercompany credit facility.

Borrowing Activities

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

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

The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of September 30, 2013, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.

The 2022 Notes were issued by Refining LLC and Coffeyville Finance and are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and

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several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, CVR Partners and Coffeyville Nitrogen Fertilizers ("CRNF") are not guarantors. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes were no longer secured as of and after January 23, 2013.

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

The 2022 Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased. 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) 103.25% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019 and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, plus in each case, any accrued and unpaid interest.

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

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

The indenture governing the 2022 Notes imposes covenants that restrict 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, 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 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 September 30, 2013.

Amended and Restated Asset Backed (ABL) Credit Facility. On December 20, 2012, CRLLC and certain subsidiaries (collectively, the “Credit Parties”) entered into the Amended and Restated ABL Credit Facility with Wells Fargo, as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced CRLLC’s 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,

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2013. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The borrowing-base components, advance rates, prepayment provisions, collateral provisions, affirmative covenants and negative covenants in the Amended and Restated ABL Credit Facility are substantially similar to the corresponding provisions in the ABL credit facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and will be used for working capital and other general corporate purposes (including permitted acquisitions).

Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. 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, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The Amended and Restated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined therein. We were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of September 30, 2013.

Intercompany Credit Facility. On January 23, 2013, prior to the closing of the Initial Public Offering, we entered into a new $150.0 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 is for 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 September 30, 2013.

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 September 30, 2013, we had borrowings of $11.5 million outstanding and $138.5 million available under the intercompany credit facility.

Old Notes. On April 6, 2010, CRLLC and Coffeyville Finance completed the private offering of $275.0 million aggregate principal amount of First Lien Notes and $225.0 million aggregate principal amount of Second Lien Notes. The 2010 First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 15, 2011, the issuers issued an additional $200.0 million aggregate principal amount of First Lien Notes to partially fund the acquisition of the Wynnewood refinery. The additional First Lien Notes were issued at 105% of their principal

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amount. As the Old Notes were incurred for the benefit of our operations, all debt and associated costs have been allocated to us. On October 23, 2012, we repurchased approximately $323.0 million of the First Lien Notes pursuant to a tender offer and we redeemed the remaining $124.1 million of outstanding First Lien Notes on November 23, 2012, as discussed above. On January 23, 2013, we used a portion of the proceeds from the Initial Public Offering to satisfy and discharge the indenture governing the Second Lien Notes and all have been redeemed.

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 nine months ended September 30, 2013 by major category:



	Nine Months Ended September 30, 2013
	(in millions)
Coffeyville refinery:
Maintenance	$	37.4
Growth	2.2
Coffeyville refinery total capital	39.6
Wynnewood refinery
Maintenance	74.0
Growth	17.1
Wynnewood refinery total capital	91.1
Other:
Maintenance	7.8
Growth	2.3
Other total capital	10.1
Total capital spending	$	140.8

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

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Cash Flows

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



	Nine Months Ended September 30,
	2013			2012
	(unaudited)
	(in millions)
Net cash provided by (used in):
Operating activities	$	483.4		$	799.2
Investing activities	(140.7		)	(82.4		)
Financing activities	(245.3		)	(640.0		)
Net increase in cash and cash equivalents	$	97.4		$	76.8

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.

Cash Flows Provided by Operating Activities

Net cash flows provided by operating activities for the nine months ended September 30, 2013 were approximately $483.4 million. The positive cash flow from operating activities generated over this period was primarily driven by $700.6 million of net income and favorable impacts to other working capital ($20.0 million), partially offset by unfavorable changes in trade working capital ($181.8 million). Trade working capital for the nine months ended September 30, 2013 resulted in a cash outflow of $181.8 million which was primarily attributable to increases in accounts receivable ($29.5 million) and inventory ($147.8 million). Other working capital activities resulted in net cash inflow of $20.0 million, which was primarily related to an increase in other current liabilities ($27.3 million).

Net cash flows provided by operating activities for the nine months ended September 30, 2012 was $799.2 million. The positive net cash flow from operating activities was primarily driven by operating income of $873.5 million, which was primarily the result of higher operating margins. This positive cash flow from operating activities was partially offset by unfavorable changes in trade working capital. Trade working capital for the nine months ended September 30, 2012 resulted in a cash outflow of approximately $71.4 million as a result of a decrease in accounts payable ($90.5 million) coupled with an increase in accounts receivable ($99.5 million), offset by a decrease in inventories ($118.6 million).

Cash Flows Used In Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2013 was $140.7 million compared to $82.4 million for the nine months ended September 30, 2012. The increase in cash used in investing activities was the result of a $58.0 million increase in capital expenditures during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, largely resulting from incremental spending at the Wynnewood refinery.

Cash Flows Used in Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2013 was approximately $245.3 million compared to net cash used in financing activities of $640.0 million for the nine months ended September 30, 2012. Prior to December 31, 2012, CRLLC historically provided cash as necessary to support our operations and retained excess cash earned by our operations. Cash received or paid by CRLLC on our behalf has been recorded as net contributions from or net distributions to parent as a component of divisional equity which is reflected as a financing activity in the Condensed Combined Statements of Cash Flows for the nine months ended September 30, 2012.

The net cash used in financing activities for the nine months ended September 30, 2013 was primarily attributable to payments to extinguish the Second Lien Notes of $243.4 million, distributions to affiliates of $235.1 million and distributions to our common unitholders of $432.5 million (including $345.5 million to affiliates), partially offset by proceeds from the initial public offering of $655.7 million. The net cash used in financing activities for the nine months ended September 30, 2012 was primarily attributable to excess cash earned in our operations that was distributed to our parent ($637.3 million).

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For the nine months ended September 30, 2013, there were no borrowings or repayments under the Amended and Restated ABL Credit Facility. As of September 30, 2013, there were no short-term borrowings outstanding under the Amended and Restated ABL Credit Facility. As of September 30, 2013, the Partnership had borrowings of $11.5 million outstanding under the intercompany loan facility.

Contractual Obligations

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of September 30, 2013 relating to long-term debt outstanding on that date, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following September 30, 2013 and thereafter. As of September 30, 2013, there were no amounts outstanding under the Amended and Restated ABL Credit Facility. As of September 30, 2013, the Partnership had borrowings of $11.5 million outstanding under the intercompany loan facility.



	Payments Due by Period
	Total		2013		2014		2015		2016		2017		Thereafter
	(in millions)
Contractual Obligations
Long-term debt(1)	$	511.5	$	—	$	—	$	—	$	—	$	—	$	511.5
Operating leases(2)	6.0		0.7		2.3		1.4		1.0		0.3		0.3
Capital lease obligations(3)	51.4		0.3		1.3		1.4		1.6		1.8		45.0
Unconditional purchase obligations(4)	1,406.6		82.7		108.5		96.7		89.6		88.4		940.7
Environmental liabilities(5)	2.1		0.2		0.4		0.2		0.1		0.1		1.1
Interest payments(6)	355.1		9.5		37.9		37.8		37.7		37.5		194.7
Total	$	2,332.7	$	93.4	$	150.4	$	137.5	$	130.0	$	128.1	$	1,693.3
Other Commercial Commitments
Standby letters of credit(7)	$	27.1	$	—	$	—	$	—	$	—	$	—	$	—

____________


(1)	Consists of the 2022 Notes and borrowings outstanding on the intercompany credit facility.


(2)	We lease various facilities and equipment, including real property, under operating leases for various periods.


(3)	The amount includes commitments under capital lease arrangements for equipment for two leases associated with pipelines, and storage and terminal equipment associated with the acquisition of the Wynnewood refinery.

(4)

The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments related to our biofuels blending obligation and (c) approximately $965.5 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between our subsidiary, CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada’s Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011.


(5)	Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. See "Commitments and Contingencies - Environmental, Health & Safety Matters.”


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


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

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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 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. 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.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. We adopted these standards as of January 1, 2013. The adoption of these standards expanded our condensed consolidated and combined financial statement footnote disclosures.

Critical Accounting Policies

Our critical accounting policies are disclosed in the “Critical Accounting Policies” section of our Annual Report on Form 10-K for the year ended December 31, 2012. No modifications have been made to our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. Information about market risks for the nine months ended September 30, 2013 does not differ materially from that discussed under Part II—Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2012. We are exposed to market pricing for all of the products sold in the future, 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, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.

Commodity Price Risk

At September 30, 2013, we had open commodity hedging instruments consisting of 20.6 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at September 30, 2013 was a net unrealized gain of $110.1 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of commodity hedging instruments of $20.6 million.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2013, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

See Note 12 ("Commitments and Contingencies") to Part I, Item I of this Report, which is incorporated by reference into this Part II, Item 1, for a description of the litigation, legal and administrative proceedings and environmental matters.

Item 1A. Risk Factors

There have been no material changes from the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 6. Exhibits



Exhibit Number		Exhibit Title
31.1*		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2*		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1*		Section 1350 Certification of Chief Executive Officer.
32.2*		Section 1350 Certification of Chief Financial Officer.
101*		The following financial information for CVR Refining, LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 1, 2013, formatted in XBRL (“Extensible Business Reporting Language”) includes: (1) Condensed Consolidated Balance Sheets (unaudited), (2) Condensed Consolidated and Combined Statements of Operations (unaudited), (3) Condensed Consolidated Statement of Changes in Partners’ Capital (unaudited), (4) Condensed and Combined Statements of Cash Flows (unaudited), and (5) the Notes to Condensed Consolidated and Combined 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

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

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