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, 2018

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 every Interactive Data File required to be submitted 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 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o

Smaller reporting company o	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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 23, 2018.

CVR REFINING, LP AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2018

(unaudited)



		Page No.
Part I. Financial Information
Item 1.	Financial Statements	3

	Condensed Consolidated Balance Sheets — September 30, 2018 and December 31, 2017	3

	Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2018 and 2017	4

	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2018 and 2017	5

	Notes to the Condensed Consolidated Financial Statements — September 30, 2018	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 4.	Controls and Procedures	34

Part II. Other Information

Item 1.	Legal Proceedings	35

Item 1A.	Risk Factors	35

Item 5.	Other Information	35

Item 6.	Exhibits	36

Signatures		37

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)



(In millions)	September 30, 2018		December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	398	$	174
Accounts receivable	194		169
Inventories	370		331
Prepaid expenses and other current assets	31		26
Total current assets	993		700
Property, plant, and equipment, net of accumulated depreciation	1,396		1,479
Other long-term assets	116		91
Total assets	$	2,505	$	2,270
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Note payable and capital lease obligations	$	2	$	2
Accounts payable	388		307
Accrued expenses and other current liabilities	103		153
Accounts payable and accrued expenses due to affiliates	18		20
Total current liabilities	511		482
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion	537		539
Other long-term liabilities	11		2
Total long-term liabilities	548		541
Commitments and contingencies (See Note 11)
Partners’ capital	1,446		1,247
Total liabilities and partners' capital	$	2,505	$	2,270

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per unit data)	2018			2017			2018			2017
Net sales	$	1,857		$	1,386		$	5,139		$	4,148
Operating costs and expenses:
Cost of materials and other	1,544			1,114			4,315			3,524
Direct operating expenses (exclusive of depreciation and amortization as reflected below)	85			120			272			308
Depreciation and amortization	33			32			98			97
Cost of sales	1,662			1,266			4,685			3,929
Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below)	18			19			56			58
Depreciation and amortization	1			1			3			3
Loss on asset disposals	—			1			5			1
Operating income	176			99			390			157
Interest expense, net	(10		)	(12		)	(32		)	(34		)
Gain (loss) on derivatives, net	5			(17		)	75			(5		)
Other income, net	3			—			6			—
Net income	$	174		$	70		$	439		$	118

Net income per common unit - basic and diluted	$	1.18		$	0.47		$	2.97		$	0.80

Weighted-average common units outstanding:
Basic and diluted	147.6			147.6			147.6			147.6

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CVR REFINING, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Nine Months Ended September 30,
(In millions)	2018			2017
Cash flows from operating activities:
Net income	$	439		$	118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	101			100
Share-based compensation	12			7
Other non-cash items	6			3
Income from equity method investments, net of distributions	(1		)	—
Changes in assets and liabilities:
Current assets and liabilities	(48		)	87
Non-current assets and liabilities	5			(1		)
Net cash provided by operating activities	514			314
Cash flows from investing activities:
Capital expenditures	(50		)	(66		)
Other investing activities	1			(1		)
Net cash used in investing activities	(49		)	(67		)
Cash flows from financing activities:
Distributions to common unitholders – affiliates	(181		)	—
Distributions to common unitholders – non-affiliates	(58		)	—
Other financing activities	(2		)	(1		)
Net cash used in financing activities	(241		)	(1		)
Net increase in cash and cash equivalents	224			246
Cash and cash equivalents, beginning of period	174			314
Cash and cash equivalents, end of period	$	398		$	560

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

(1) Organization and Nature of Business

CVR Refining, LP and subsidiaries (“CVR Refining” or the “Partnership”) is a refiner that does not have crude oil exploration or production operations (an “independent petroleum refiner”) and is a marketer of high value transportation fuels. The Partnership owns a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a complex crude oil refinery in Wynnewood, Oklahoma. During August 2018, CVR Energy, Inc. (“CVR Energy”) completed an exchange offer whereby public unitholders tendered a total of 21,625,106 CVR Refining common units in exchange for a total of 13,699,549 shares of CVR Energy common stock. As of September 30, 2018, CVR Energy and CVR Refining Holdings, LLC (“CVR Refining Holdings”), an indirect wholly-owned subsidiary of CVR Energy, owned 100% of the Partnership’s noneconomic general partner interest and approximately 81% of the Partnership’s outstanding limited partner interests. As of September 30, 2018, Icahn Enterprises L.P. (“IEP”) and its affiliates owned approximately 71% of CVR Energy’s outstanding shares. CVR Refining’s common units, which are listed on the New York Stock Exchange (“NYSE”), began trading on January 17, 2013 under the symbol “CVRR.”

Management and Operations

The Partnership is party to a services agreement pursuant to which the Partnership and its general partner obtain certain management and other services from CVR Energy. The Partnership’s general partner manages the Partnership’s activities subject to the terms and conditions specified in CVR Refining’s partnership agreement. The operations of the general partner, in its capacity as general partner, are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CVR Refining Holdings, LLC (“CVR Refining Holdings”), a subsidiary of Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, 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 also has agreements with a subsidiary of CVR Partners, LP (“CVR Partners”), an indirect subsidiary of CVR Energy, under which the Partnership sells petroleum coke and hydrogen to CVR Partners Coffeyville Facility. Additionally, the two parties provide feedstock and other services to one another at the Coffeyville Facility. See Note 14 ("Related Party Transactions") for further discussion.

(2) Basis of Presentation

The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). These condensed consolidated financial statements should be read in conjunction with the December 31, 2017 audited consolidated financial statements and notes thereto included in CVR Refining’s Annual Report on Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 26, 2018 (the “2017 Form 10-K”).

The condensed consolidated financial statements include certain selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization) that CVR Energy and its affiliates incurred on behalf of and charged to the Partnership. These related party transactions are governed by the services agreement. See Note 14 ("Related Party Transactions") for additional discussion of the services agreement and billing of certain costs.

In the opinion of the Partnership’s management, the accompanying condensed consolidated financial statements reflect all adjustments that are necessary to fairly present the financial position of the Partnership as of September 30, 2018 and December 31, 2017, the results of operations of the Partnership for the three and nine month periods ended September 30, 2018 and 2017 and the cash flows of the Partnership for the nine month periods ended September 30, 2018 and 2017. Such adjustments are of a normal recurring nature, unless otherwise disclosed. Certain information has been reclassified to present historical information in a manner consistent with current presentation.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The preparation of the condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2018 or any other interim or annual period.

(3) Recent Accounting Pronouncements

Adoption of New Revenue Standard

On January 1, 2018, the Partnership adopted the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers” (“ASC 606”) using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. The standard was applied prospectively and the comparative information for 2017 has not been restated and continues to be reported under the accounting standards in effect for the prior period. The Partnership did not identify any material differences in its existing revenue recognition methods that require modification under the new standard and, as such, a cumulative effect adjustment of applying the standard using the modified retrospective method was not recorded.

Impact on Financial Statements

The Partnership identified a presentation change associated with a fee collected from certain customers that were previously recorded as a reduction to cost of materials and other. The particular fee, the Oil Spill Liability Tax, relates to taxes imposed on refineries as part of the crude oil procurement process, and is charged to certain of the Partnership’s customers on product sales and is required under the new standard to be included in the transaction price. The impact of the change in presentation was an increase of $1 million and $1 million to net sales and cost of materials and other for the three and nine months ended September 30, 2018, respectively.

New Accounting Standards Issued But Not Yet Implemented

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (“ASU 2016-02”), creating a new topic, FASB ASC Topic 842, “Leases” (“Topic 842”), which supersedes lease requirements in FASB ASC Topic 840, “Leases”. The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability related to future lease payments and an asset representing its right to use of the underlying asset for the lease term on the balance sheet. Quantitative and qualitative disclosures, including disclosures regarding significant judgments made by management, will be required. In July 2018, the FASB issued updated guidance which provides entities with an additional transition method to adopt Topic 842. Under the new transition method, an entity initially applies the new leases standard at the adoption date, versus at the beginning of the earliest period presented, and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership expects to elect this transition method at the adoption date of January 1, 2019. The Partnership also plans to elect the short-term lease exception provided for in the standard and therefore will only recognize right-of-use assets and lease liabilities for leases with a term greater than one year. The Partnership continues to focus its implementation efforts on accounting policy and disclosure updates along with the system implementation necessary to meet the standard’s requirements. Based on information available to date, the Partnership estimates the operating lease right of use asset and lease liability may approximate $25 - $70 million upon adoption. This preliminary estimate of the effect on the Partnership’s Consolidated Balance Sheets as a result of implementing the standard on January 1, 2019 could differ materially depending on guidance changes from the FASB, changes in outstanding leases, final verification of the Partnership’s lease accounting estimates, and any changes in the Partnership’s plans to elect certain practical expedients. The Partnership does not expect the adoption of this standard to have a material impact on the recognition, measurement or presentation of amounts within the Condensed Consolidated Statements of Operations and the Condensed Consolidated Statements of Cash Flows.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40). This ASU addresses customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract and also adds certain disclosure requirements related to implementation costs incurred for internal-use software and cloud computing arrangements. The amendment aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). This standard is effective for the Partnership beginning January 1, 2020, with early adoption permitted. The amendments in this standard can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Partnership is evaluating the effect of adopting this new accounting guidance on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820). The ASU eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. This standard is effective for the Partnership beginning January 1, 2020, with early adoption permitted. The Partnership is evaluating the effect of adopting this new accounting guidance, but does not expect adoption will have a material impact on the Partnership’s disclosures.

(4) Revenue

The following table presents the Partnership’s revenue disaggregated by major product.



(In millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Major Product
Gasoline	$	951	$	2,558
Distillates (a)	840		2,324
Freight revenue	6		17
Other (b)	47		161
Revenue from product sales	1,844		5,060

Crude oil sales	12		75
Other revenue	1		4
Total revenue	$	1,857	$	5,139


(a)	Distillates consist primarily of diesel fuel, kerosene and jet fuel.


(b)	Other revenue consists primarily of feedstock and asphalt sales and Cushing, OK storage tank lease revenue. See Note 7 (Property, Plant and Equipment) for further discussion.

The Partnership’s revenue from product sales is recorded upon delivery of the products to customers, which is the point at which title is transferred and the customer has assumed the risk of loss. This generally takes place as product passes into the pipeline, as a product transfer order occurs within a pipeline system, or as product enters equipment or locations supplied or designated by the customer. The Partnership has elected to apply the sales tax practical expedient, whereby qualifying excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.

Many of the Partnership’s contracts have index-based pricing which is considered variable consideration that should be estimated in determining the transaction price. The Partnership determined that it does not need to estimate the variable consideration because the uncertainty related to the consideration is resolved on the pricing date or the date when the product is delivered.

The Partnership may incur broker commissions or transportation costs prior to product transfer on some of its sales. The Partnership has elected to apply the practical expedient allowing it to expense the broker costs since the contract durations are less

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

than a year in length. Transportation costs are accounted for as fulfillment costs and are expensed as incurred since they do not meet the requirement for capitalization.

The Partnership’s contracts with its customers state the terms of the sale, including the description, quantity, and price of each product sold. Depending on the product sold, payment from customers is generally due in full within 2 to 32 days of product delivery or invoice date. The Partnership’s contracts with customers commonly include a provision which states that the Partnership will accept customer returns of off-spec product, refund the customer (or provide on-spec product), and pay for damages to any customer equipment which resulted from the off-spec product. Typically, if the customer is not satisfied with the product, the price is adjusted downward instead of the product being returned or exchanged. The Partnership has determined that product returns or refunds are very rare and will account for them as they occur. The Partnership generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification.

Freight revenue recognized by the Partnership is primarily tariff and line loss charges that are re-billed to customers to reimburse the Partnership for expenses incurred from a pipeline operator. An offsetting expense for freight is included in cost of materials and other.

Transaction price allocated to remaining performance obligations

As of September 30, 2018, approximately $41 million of revenue from remaining performance obligations is expected to be recognized from a contract with an initial duration of greater than one year. The Partnership will recognize revenue ratably each month through 2036 as the take-or-pay obligations under the Hydrogen Purchase and Sale Agreement are satisfied or expire.

The Partnership does not disclose variable consideration related to index-based or market-based pricing as it qualifies for the variable consideration allocation exception under the new revenue standard. The variable consideration relates specifically to the Partnership’s efforts to transfer each unit of product to the customer in which the pricing is directly related to the period to which the sale occurs.

(5) Share-Based Compensation

A summary of share-based compensation expense during the three and nine months ended September 30, 2018 and 2017 are presented below:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2018		2017		2018		2017
Phantom Units	$	1	$	1	$	8	$	4
Other Awards (a)	2		1		4		3
Total Share-Based Compensation Expense	$	3	$	2	$	12	$	7


(a)	Other awards include the allocation of compensation expense for certain employees of CVR Energy who perform services for the Partnership under the services agreement with CVR Energy and participate in equity compensation plans of CVR Refining affiliates.

(6) Inventories

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)



(In millions)	September 30, 2018		December 31, 2017
Raw materials and precious metals	$	133	$	108
In-process inventories	19		22
Finished goods	175		158
Parts and supplies	43		43
Total Inventories	$	370	$	331

(7) Property, Plant and Equipment



(In millions)	September 30, 2018		December 31, 2017
Land and improvements	$	30	$	30
Buildings	64		64
Machinery and equipment	2,372		2,375
Other	96		79
	2,562		2,548
Less: Accumulated depreciation	1,166		1,069
Total property, plant and equipment, net	$	1,396	$	1,479

Capitalized interest recognized as a reduction in interest expense was immaterial for both of the three and nine month periods ended September 30, 2018 and 2017.

During the period, the Partnership began actively marketing assets with a carrying value of $27 million at September 30, 2018. The carrying value of these assets held for sale were included in other long-term assets on the Partnership’s Condensed Consolidated Balance Sheets. No loss was recognized upon designation of these assets as held for sale.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

(8) Long-Term Debt



Debt Balance, Net of Current Maturities and Unamortized Issuance Costs
(In millions)	September 30, 2018			December 31, 2017
6.50% Senior Notes due 2022 (a)	$	500		$	500
Capital lease obligations	43			45
Total long-term debt, before debt issuance costs and discount	543			545
Less:
Unamortized debt issuance costs	(4		)	(4		)
Current portion of capital lease obligations	(2		)	(2		)
Total long-term debt, net of current portion	$	537		$	539


(a)	The estimated fair value of total long-term debt outstanding was approximately $508 million and $515 million as of September 30, 2018 and December 31, 2017, respectively.



Credit Facilities Outstanding
	Total Capacity		Amount Borrowed as of September 30, 2018		Outstanding Letters of Credit		Available Capacity as of September 30, 2018		Maturity Date

Amended and Restated Asset Based (ABL) Credit Facility (b)	$	400	$	—	$	6	$	394	November 14, 2022
Intercompany Credit Facility (c)	150		—		—		150		January 23, 2019


(b)	Loans under the ABL credit facility initially bear interest at an annual rate equal to (i) 1.50% plus LIBOR or (ii) 0.50% plus a base rate, subject to quarterly excess availability.


(c)	The intercompany credit facility bears interest at a rate of LIBOR plus 3% per annum, payable quarterly.

The Partnership is in compliance with all covenants of the ABL credit facility and the 6.50% senior notes as of September 30, 2018.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

(9) Partners' Capital and Partnership Distributions

The Partnership had two types of partnership interests outstanding at September 30, 2018, common units and general partner interests. General partner interests are not entitled to any distributions, and are held by the general partner. At September 30, 2018, the Partnership had a total of 147,600,000 common units issued and outstanding, of which 97,315,764 common units were owned by CVR Refining Holdings and 21,625,106 common units were owned by CVR Energy, representing approximately 81% of the total Partnership common units outstanding.

Distributions

The board of directors of the Partnership’s general partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the general partner following the end of such quarter.

The following is a summary of cash distributions paid to the Partnership’s unitholders during 2018 for the respective quarters to which the distributions relate:



(In millions, except per unit data)	December 31, 2017		March 31, 2018		June 30, 2018		Total Cash Distributions Paid in 2018
Amount paid to CVR Refining Holdings, LLC and affiliates	$	47	$	52	$	82	$	181
Amounts paid to non-affiliates	20		23		15		58
Total amount paid	$	67	$	75	$	97	$	239

Per common unit	$	0.45	$	0.51	$	0.66	$	1.62
Common units outstanding	147.6		147.6		147.6

On October 24, 2018, the board of directors of the Partnership’s general partner declared a cash distribution for the third quarter of 2018 to the Partnership’s unitholders of $0.90 per common unit, or $133 million in aggregate. The cash distribution will be paid on November 12, 2018 to unitholders of record at the close of business on November 5, 2018.

(10) Supplemental Cash Flow Information

Cash flows related to interest and construction in process were as follows:



	Nine Months Ended September 30,
(In millions)	2018		2017
Supplemental disclosures:
Cash paid for interest	$	24	$	26
Non-cash investing and financing activities:
Construction in process additions included in accounts payable	8		7
Change in accounts payable related to construction in process additions	1		(2		)

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

(11) Commitments and Contingencies

There have been no material changes in the Partnership’s commitments and contingencies disclosed in the 2017 Form 10-K. In the ordinary course of business, the Partnership may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. The outcome of these matters cannot always be predicted accurately, but the Partnership accrues liabilities for these matters if the Partnership has determined that it is probable a loss has been incurred and the loss can be reasonably estimated. While it is not possible to predict the outcome of such proceedings, if one or more of them were decided against us, the Partnership believes there would be no material impact on its consolidated financial statements.

Crude Oil Supply Agreement

On August 31, 2012, Coffeyville Resource Refining & Marketing, LLC (“CRRM”) and Vitol Inc. (“Vitol”) entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the “Vitol Agreement”). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Partnership’s inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a “Renewal Term”) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2019.

Renewable Fuel Standards

CVR Refining is subject to the Renewable Fuel Standard (“RFS”) of the Environmental Protection Agency (“EPA”), which requires refiners to either blend “renewable fuels” in with their transportation fuels or purchase renewable fuel credits, known as renewable identification numbers (“RINs”), in lieu of blending. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. transportation fuel market, there may be a decrease in demand for petroleum products. CVR Refining is not able to blend the substantial majority of its transportation fuels and has to purchase RINs on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS.

The price of RINs has been extremely volatile over several years. The cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of CVR Refining’s petroleum products, as well as the fuel blending performed at its refineries and downstream terminals, all of which can vary significantly from period to period.

The net cost of RINs for the three months ended September 30, 2018 and 2017 was $20 million and $64 million, respectively. The net cost of RINs for the nine months ended September 30, 2018 and 2017 was $47 million and $164 million, respectively. The net cost of RINs is included in cost of materials and other in the Condensed Consolidated Statements of Operations. RINs expense includes the purchased cost of RINs, the impact of recognizing the Partnership’s uncommitted biofuel blending obligation at fair value based on market prices at each reporting date and is reduced by the valuation change of RINs purchases in excess of the Partnership’s RFS obligation as of the reporting date. As of September 30, 2018 and December 31, 2017, CVR Refining’s biofuel blending obligation was approximately $7 million and $28 million, respectively, which is recorded in accrued expenses and other current liabilities in the Condensed Consolidated Balance Sheets. The Partnership included a RINs asset within prepaid and other current assets in the Condensed Consolidated Balance Sheet of $4 million, representing excess RINs primarily due to a reduction in its RFS obligation during the first quarter of 2018.

Litigation

On August 21, 2018, CRRM received a letter from the United States Department of Justice (“DOJ”) on behalf of the EPA and Kansas Department of Health and Environment (“KDHE”) alleging violations of the Clean Air Act (“CAA”) and a 2012 Consent Decree between CRRM, the United States (on behalf of EPA) and KDHE at CRRM’s Coffeyville refinery. In September 2018, CRRM executed a tolling agreement with DOJ and KDHE extending time for negotiation regarding the agencies’ allegations through March 31, 2019. At this time the Partnership cannot reasonably estimate the potential penalties, costs, fines or other expenditures that may result from this matter or any subsequent enforcement or litigation relating thereto and, therefore, the Partnership cannot determine if the ultimate outcome of this matter will have a material impact on the Partnership’s financial position, results of operations or cash flows.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

(12) Fair Value Measurements

In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures (“ASC 820”), the Partnership utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets or liabilities, such as a business.

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


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


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


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

The following tables set forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of September 30, 2018 and December 31, 2017:



	September 30, 2018
(In millions)	Level 1		Level 2			Level 3		Total
Commodity derivatives	$	—	$	(30	)	$	—	$	(30	)
Biofuel blending obligation	—		(2		)	—		(2		)
Total other current liabilities	$	—	$	(32	)	$	—	$	(32	)



	December 31, 2017
(In millions)	Level 1		Level 2			Level 3		Total
Commodity derivatives	$	—	$	(64	)	$	—	$	(64	)
Biofuel blending obligation	—		(1		)	—		(1		)
Total other current liabilities	$	—	$	(65	)	$	—	$	(65	)

As of September 30, 2018 and December 31, 2017, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining’s derivative instruments and uncommitted biofuel blending obligation. The commodity derivative contracts and the uncommitted biofuel blending obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, are considered Level 2 inputs. CVR Refining had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2018.

(13) Derivative Financial Instruments

CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR Refining from time to time enters into various commodity derivative transactions. CVR Refining does not apply hedge accounting with respect to derivative instruments held. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 under GAAP. There are no premiums paid or received at inception of the derivative contracts and upon settlement.

CVR Refining enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, CVR Refining may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. The fair value of the outstanding contracts at September 30, 2018 and December 31, 2017 was a net unrealized loss of $30 million and $64 million, respectively, all of which was included in other current liabilities. A change of $1.00 per barrel in the fair value of the benchmark crude or product basis would result in an increase or decrease in the related fair value of the commodity instruments and forward purchase and sale commitments of $1 million.



Gain (Loss) on Derivatives
	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2018		2017			2018			2017
Gain (loss) on derivatives, net:
Forward purchases	$	4	$	—		$	33		$	—
Swaps	—		(17		)	43			(5		)
Futures	1		—			(1		)	—
Total gain (loss) on derivatives, net	$	5	$	(17	)	$	75		$	(5	)



Open Commodity Derivative Instruments
(In millions of barrels)	September 30, 2018	December 31, 2017
Commodity Swap Instruments:
2-1-1 Crack spreads	—	7
Distillate Crack spreads	—	4
Gasoline Crack spreads	—	4
Purchase and Sale Commitments:
Canadian crude oil	2	6

Offsetting Assets and Liabilities

The commodity swap 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 commodity swap derivative positions have been presented net in the Condensed Consolidated Balance Sheets. The tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Condensed Consolidated Balance Sheets for the various types of open derivative positions.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The offsetting assets and liabilities for CVR Refining’s derivatives as of September 30, 2018 and December 31, 2017 are recorded as current assets and current liabilities in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:



	Derivative Assets						Derivative Liabilities
(In millions)	September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Commodity Derivatives	$	5		$	7		$	35		$	71
Less: Counterparty Netting	(5		)	(7		)	(5		)	(7		)
Total Net Fair Value of Derivatives	$	—		$	—		$	30		$	64

Commodity derivatives include commodity swaps and forward purchase and sale commitments. There were no outstanding commodity swap positions as of September 30, 2018.

(14) Related Party Transactions

A summary of activity associated with the Partnership’s related party arrangements during the three and nine month periods ended September 30, 2018 and 2017 is summarized below:



Sales and Expenses with related parties
		Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	Related Party	2018		2017		2018		2017
Sales
Hydrogen Purchase and Sale Agreement	CRNF (1)	$	1	$	1	$	3	$	3
Coke Supply Agreement	CRNF	1		1		2		2

Direct operating expenses (exclusive of depreciation and amortization)
Services Agreement	CVR Energy	$	3	$	3	$	8	$	9

Selling, general and administrative expenses (exclusive of depreciation and amortization)
Services Agreement	CVR Energy	$	11	$	12	$	34	$	36
Limited Partnership Agreement	CVR Refining GP	2		2		7		7


(1)	Coffeyville Resources Nitrogen Fertilizers, LLC

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)



Amounts due to and from related parties
(In millions)	Related Party	September 30, 2018		December 31, 2017
Prepaid and Other Current Assets
Feedstock and Shared Services Agreement:	CRNF	$	1	$	1

Accounts Payable
Services Agreement:	CVR Energy	3		3

Accrued expenses and other current liabilities
Services Agreement:	CVR Energy	$	9	$	14

Intercompany Credit Facility

The Partnership has an intercompany credit facility with CRLLC with a borrowing capacity of $150 million. As of September 30, 2018, the Partnership had no borrowings outstanding under the intercompany credit facility. For both the three months ended September 30, 2018 and 2017, the Partnership paid no interest to CRLLC. For both the nine months ended September 30, 2018 and 2017, the Partnership paid no interest to CRLLC.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 filed with the Securities and Exchange Commission (“SEC”) on February 26, 2018 (“2017 Form 10-K”). Results of operations and cash flows for the three and nine months ended September 30, 2018 are not necessarily indicative of results to be attained for any other period. Refer to the section entitled “Forward-Looking Statements”.

Partnership Overview

CVR Refining, LP (“CVR Refining,” the “Partnership,” “we,” “us” or “our”) is an independent downstream energy limited partnership with refining and related logistics assets that operates two of only seven refineries in Group 3 of the PADD II region of the United States. We own and operate a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a capacity of 132,000 barrels per calendar day (“bpcd”) and a complex crude oil refinery in Wynnewood, Oklahoma with a capacity of 74,500 bpcd capable of processing 20,000 bpcd of light sour crude oils (within its capacity of 74,500 bpcd). In addition, we also control and operate supporting logistics assets throughout our operational area. Refer to our 2017 Form 10-K for further information on our assets and related operations.

During July 2018, CVR Energy Inc. (“CVR Energy”) completed an exchange offer whereby public unitholders tendered a total of 21,625,106 common units of CVR Refining in exchange for a total of 13,699,549 shares of CVR Energy common stock. The exchange offer was made only to then current holders of CVR Refining and was not made or offered to the public or any other security holders. In connection with this exchange offer, we incurred $0.1 million of costs, which were capitalized to additional paid-in-capital.

Major Influences on Results of Operations

Our earnings and cash flows are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery (“refined products”). The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond 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 volatile seasonal exports of diesel from the United States Gulf Coast markets.

In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations and increased mileage standards for vehicles. We are also subject to the Renewable Fuel Standard (“RFS”) of the Environmental Protection Agency (“EPA”), which requires us to either blend “renewable fuels” in with our transportation fuels or purchase renewable identification numbers (“RINs”), in lieu of blending, by March 31, 2019 or otherwise be subject to penalties. The cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to other variable factors, we currently estimate that the net cost of RINs will be approximately $60 - $65 million for the year ending December 31, 2018.

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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. The next turnaround scheduled for the Wynnewood refinery is being performed as a two phase turnaround. The first phase of its current turnaround was completed in November 2017 at a total cost of approximately $67 million. The second phase of the Wynnewood turnaround is expected to occur in the first half of 2019. Turnaround expenses associated with the second phase of the Wynnewood turnaround are estimated to be approximately $25 million. In addition to the two phase turnaround, we accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. We incurred approximately $13 million of major turnaround expenses for the hydrocracker. The next turnaround scheduled for the Coffeyville refinery is expected to be performed in the first half of 2020.

Non-GAAP Measures

Our management uses certain non-GAAP performance measures to analyze operating segment performance and non-GAAP financial measures to evaluate past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S. GAAP. These financial and operational non-GAAP measures are important factors in assessing our operating results and profitability and include performance and liquidity measures along with certain key operating metrics.

Performance and Liquidity Measures

We use the following performance and liquidity measures:

EBITDA. EBITDA is a performance measure representing 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. Adjusted EBITDA is a performance measure representing EBITDA adjusted for (i) (favorable) unfavorable FIFO impacts associated with our crude oil and refined product inventories, (ii) major turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and adjusted EBITDA), (iii) (gain) loss on derivatives, net and (iv) current period settlements on derivative contracts. Adjusted EBITDA represents the starting point for determining available cash for distribution. Refer to discussion below for the Refining margin, adjusted for FIFO impact non-GAAP measure for discussion of why management adjusted for the FIFO impact of our inventories. We exclude major turnaround expenses because these amounts are required expenditures for our refineries, are not closely related to current period operations, and many of our peer companies capitalize these amounts thereby excluding these amounts from their EBITDA-related measures. For derivatives, we adjust EBITDA to exclude the unrealized or non-cash portion of our derivative gain or loss from our results in order to arrive at our starting point for available cash for distribution.

Refining margin. This performance measure represents the difference between net sales and cost of materials and other as reported on our Condensed Consolidated Statements of Operations.

Refining margin, adjusted for FIFO impact. This performance measure represents our refining margin adjusted to exclude the impact of price changes in our crude oil and refined products inventories. Under our FIFO accounting method for crude oil and refined products, changes in crude oil prices can cause fluctuations in the inventory valuation of our raw material, work in process and finished good inventories, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. In periods of significant price volatility, these price changes have a significant impact on the valuation on our inventories and thus our results.

Available cash for distribution. This performance and liquidity measure is equal to Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distribution (if any) may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner.

Operating Metrics

During the second quarter of 2018, we changed the metrics discussed below from a crude oil throughput barrel basis to a total throughput barrel basis. Prior period information has been revised to conform to current presentation.

Refining margin and refining margin adjusted for FIFO impact per total throughput barrel. For both refining margin and refining margin adjusted for FIFO impact, we present these measures on a per total throughput barrel basis. In order to calculate

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these non-GAAP operating metrics, we utilize the total dollar figures for refining margin and refining margin adjusted for FIFO impact, as derived above and divide by the applicable number of total throughput barrels for the period.

Direct operating expenses, excluding major turnaround expenses, per total throughput barrel. We provide this performance measure to exclude major turnaround expenses from the reported amounts of direct operating expense during a given period. Major turnaround expenses are required are not directly correlated to our current period operations and thus excluding them provides investors and analysts with the current period cost, exclusive of depreciation and amortization, we incur to convert a barrel of crude oil into refined product.

We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results, including but not limited to our operating performance as compared to other publicly traded companies in the refining industry, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures.

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Results of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017
Consolidated Statements of Operations Data
Net sales	$	1,857		$	1,386		$	5,139		$	4,148
Operating costs and expenses:
Cost of materials and other	1,544			1,114			4,315			3,524
Direct operating expenses (1)	85			120			272			308
Depreciation and amortization	33			32			98			97
Cost of sales	1,662			1,266			4,685			3,929
Selling, general and administrative expenses (1)	18			19			56			58
Depreciation and amortization	1			1			3			3
Loss on asset disposals	—			1			5			1
Operating income	176			99			390			157
Interest expense, net	(10		)	(12		)	(32		)	(34		)
Gain (loss) on derivatives, net	5			(17		)	75			(5		)
Other income, net	3			—			6			—
Net income	$	174		$	70		$	439		$	118

Gross profit	$	195		$	120		$	454		$	219
Refining margin (2)	313			272			824			624
Adjusted EBITDA (2)	221			139			494			296
Available cash for distribution (2)	$	133		$	139		$	306		$	139



	Three Months Ended September 30,						Nine Months Ended September 30,
(In dollars per total throughput barrel)	2018			2017			2018			2017
Key Operating Statistics:
Gross profit	$	9.70		$	6.07		$	7.99		$	3.61
Refining margin (2)	$	15.54		$	13.81		$	14.50		$	10.32
FIFO impact, (favorable) unfavorable	$	(0.13	)	$	(0.76	)	$	(0.79	)	$	0.01
Refining margin adjusted for FIFO impact (2)	$	15.41		$	13.05		$	13.71		$	10.33
Direct operating expenses (1)	$	4.23		$	6.12		$	4.79		$	5.11
Direct operating expenses excluding major turnaround expenses (1)(2)	$	4.17		$	5.02		$	4.77		$	4.49


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


(2)	See “Non-GAAP Reconciliations” section below for further information regarding these non-GAAP measures.

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	Three Months Ended September 30,						Nine Months Ended September 30,
(In dollars per barrel)	2018			2017			2018			2017
Market Indicators:
West Texas Intermediate (WTI) NYMEX	$	69.43		$	48.20		$	66.79		$	49.36
Crude Oil Differentials:
WTI less WTS (light/medium sour)	14.26			0.97			8.14			1.15
WTI less WCS (heavy sour)	27.76			10.48			23.77			11.42
WTI less condensate	0.37			0.12			0.40			0.12
Midland Cushing Differential	14.33			0.79			7.69			0.54
NYMEX Crack Spreads
Gasoline	16.96			20.42			17.69			17.74
Heating Oil	22.03			21.05			21.59			17.24
NYMEX 2-1-1 Crack Spread	19.50			20.73			19.64			17.49
PADD II Group 3 Basis:
Gasoline	(0.13		)	(1.18		)	(2.16		)	(2.37		)
Ultra Low Sulfur Diesel	0.89			0.85			0.08			(0.44		)
PADD II Group 3 Product Crack Spread:
Gasoline	16.83			19.23			15.53			15.37
Ultra Low Sulfur Diesel	22.92			21.90			21.67			16.80
PADD II Group 3 2-1-1	19.88			20.57			18.60			16.09



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
		%		%		%		%
Total Refining Throughput and Production Data (bpd)
Throughput:
Condensate	8,425	3.8	1	—	13,156	6.3	2,893	1.3
Sweet	193,727	88.5	196,341	91.9	179,964	86.5	195,857	88.5
Heavy sour	6,746	3.1	6,751	3.2	4,518	2.2	11,643	5.3
Total crude oil throughput	208,898	95.4	203,093	95.1	197,638	95.0	210,393	95.1
All other feedstocks and blendstocks	10,008	4.6	10,513	4.9	10,454	5.0	10,943	4.9
Total throughput	218,906	100.0	213,606	100.0	208,092	100.0	221,336	100.0
Production:
Gasoline	111,087	50.8	105,712	49.5	103,258	49.6	112,268	50.6
Distillate	94,157	43.0	89,655	42.0	89,325	42.9	92,046	41.5
Other (excluding internally produced fuel)	13,497	6.2	18,107	8.5	15,486	7.5	17,385	7.9
Total refining production (excluding internally produced fuel)	218,741	100.0	213,474	100.0	208,069	100.0	221,699	100.0

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
		%		%		%		%
Coffeyville Refinery Throughput and Production Data (bpd)
Throughput:
Condensate	273	0.2	1	—	6,448	5.1	2,893	2.1
Sweet	127,792	90.3	121,709	89.6	109,937	86.4	116,468	83.7
Heavy sour	6,746	4.8	6,751	5.0	4,518	3.6	11,643	8.4
Total crude oil throughput	134,811	95.3	128,461	94.6	120,903	95.1	131,004	94.2
All other feedstocks and blendstocks	6,664	4.7	7,415	5.4	6,238	4.9	8,124	5.8
Total throughput	141,475	100.0	135,876	100.0	127,141	100.0	139,128	100.0
Production:
Gasoline	72,337	50.7	67,598	49.1	62,543	48.7	70,697	50.1
Distillate	60,521	42.4	57,654	41.9	54,914	42.7	58,927	41.7
Other (excluding internally produced fuel)	9,900	6.9	12,355	9.0	11,066	8.6	11,619	8.2
Total refining production (excluding internally produced fuel)	142,758	100.0	137,607	100.0	128,523	100.0	141,243	100.0



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
		%		%		%		%
Wynnewood Refinery Throughput and Production Data (bpd)
Throughput:
Condensate	8,152	10.5	—	—	6,708	8.3	—	—
Sweet	65,936	85.2	74,632	96.0	70,026	86.5	79,389	96.6
Total crude oil throughput	74,088	95.7	74,632	96.0	76,734	94.8	79,389	96.6
All other feedstocks and blendstocks	3,344	4.3	3,098	4.0	4,216	5.2	2,819	3.4
Total throughput	77,432	100.0	77,730	100.0	80,950	100.0	82,208	100.0
Production:
Gasoline	38,750	51.0	38,114	50.2	40,715	51.2	41,571	51.6
Distillate	33,636	44.3	32,001	42.2	34,411	43.2	33,119	41.2
Other (excluding internally produced fuel)	3,597	4.7	5,752	7.6	4,420	5.6	5,766	7.2
Total refining production (excluding internally produced fuel)	75,983	100.0	75,867	100.0	79,546	100.0	80,456	100.0

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Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Refining Margin. For the three months ended September 30, 2018 compared to the three months ended September 30, 2017, the NYMEX 2-1-1 crack spread declined by $1.23 per barrel, led by a decrease in gasoline and offset by an increase in distillate. The Group 3 2-1-1, while also declining by $0.69 per barrel, strengthened when compared to the NYMEX national benchmark due to the region’s gasoline price falling by $1.06 per barrel less than NYMEX gasoline. The crude oil that our refineries acquire and process had widened discounts versus WTI for the three months ended September 30, 2018 compared to the three months ended September 30, 2017. WCS and Midland crude supply availability and take-away constraints widened the discounts to WTI by $17.28 and $13.54 per barrel, respectively. In addition, the weighted average price of RINs declined by $0.64 for the three months ended September 30, 2018 compared to the three months ended September 30, 2017.

For the three months ended September 30, 2018, our refining margin was $313 million or $15.54 per throughput barrel, as compared to $272 million or $13.81 per throughput barrel for the three months ended September 30, 2017 primarily due to reduced RINs expense and increased refined product sales volumes, partially offset by decreased refined product crack spreads. Overall sales volumes increased approximately 3.5% for the three months ended September 30, 2018, as compared to the three months ended September 30, 2017 primarily due to an inventory build in preparation for a fall turnaround at our Wynnewood refinery in the prior period.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) were $85 million for three months ended September 30, 2018, compared to $120 million for the three months ended September 30, 2017. The decrease of approximately $35 million was primarily due to a decrease in major scheduled turnaround in late September in 2017.

Gain (loss) on derivatives, net. For the three months ended September 30, 2018, we recorded a $5 million net gain on derivatives, as compared to a $17 million net loss on derivatives for the three months ended September 30, 2017. This change was primarily due to a decrease in the volume of open derivative positions from 16 million barrels as of September 30, 2017 to 2 million barrels as of September 30, 2018. Additionally, the market fluctuations associated with our derivative positions can materially impact our gain or loss on derivatives.

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Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Refining Margin. For the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, the NYMEX 2-1-1 crack spread increased by $2.15 per barrel, primarily due to an improved distillate crack. The Group 3 2-1-1 also improved in 2018 by $2.51 compared to the same period last year, again driven largely by the distillate crack. The crude oil that our refineries acquire and process had widened discounts versus WTI for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. WCS and Midland crude supply availability and take-away constraints widened the discounts to WTI by $12.35 and $7.15 per barrel, respectively. In addition, the weighted average price of RINs declined by $0.33 for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.

For the nine months ended September 30, 2018 our refining margin was $824 million or $14.50 per throughput barrel, as compared to $624 million or $10.32 per throughput barrel for the nine months ended September 30, 2017 primarily due to increased refined product crack spreads and reduced RINs expense, offset by reduced sales volumes. Overall sales volumes decreased approximately 4.8% for the nine months ended September 30, 2018, as compared the nine months ended September 30, 2017, primarily due to decreased production as a result of the fluid catalytic cracking unit (“FCCU”) outage at the Coffeyville refinery during the first quarter of 2018, offset by improved sales volume in the third quarter of 2018 as volume reduced in 2017 in preparation of the Wynnewood turnaround.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct Operating Expenses (Exclusive of Depreciation and Amortization) were $272 million for the nine months ended September 30, 2018 compared to $308 million for the nine months ended September 30, 2017. The decrease of approximately $36 million was primarily due to a decrease in major scheduled turnaround in late September in 2017.

Gain (loss) on derivatives, net. For the nine months ended September 30, 2018, we recorded a $75 million net gain on derivatives, as compared to a $5 million net loss on derivatives for the nine months ended September 30, 2017. This change was primarily due to a decrease in the volume of open derivative positions in from 16 million barrels as of September 30, 2017 to 2 million barrels as of September 30, 2018. Additionally, the market fluctuations associated with our derivative positions can materially impact our gain or loss on derivatives.

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Non-GAAP Reconciliations

Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Available Cash for Distribution



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017
Net income	$	174		$	70		$	439		$	118
Add:
Interest expense, net	10			12			32			34
Depreciation and amortization	34			33			101			100
EBITDA	218			115			572			252
Add:
FIFO impact, (favorable) unfavorable (a)	(3		)	(15		)	(45		)	1
Major turnaround expenses (b)	1			22			1			37
(Gain) loss on derivatives, net	(5		)	17			(75		)	5
Current period settlements on derivative contracts (c)	10			—			41			1
Adjusted EBITDA	$	221		$	139		$	494		$	296

(a)

FIFO is our basis for determining inventory value under GAAP. 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 impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per total throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of total throughput barrels for the period.


(b)	Represents expense associated with major turnaround activities at the Wynnewood refinery during 2017.


(c)	Represents the portion of gain 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. Upon settlement there is no cost recovery associated with these contracts.



(In millions, except per unit data)	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Reconciliation of Adjusted EBITDA to Available cash for distribution
Adjusted EBITDA	$	221		$	494
Adjustments:
Less:
Cash needs for debt service	(10		)	(30		)
Maintenance capital expenditures	(25		)	(75		)
Reserves for major turnaround expenses	(15		)	(45		)
Reserves for projects	(38		)	(38		)
Available cash for distribution	$	133		$	306

Distribution declared, per common unit	$	0.90		$	2.07
Common units outstanding	147.6			147.6

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Reconciliation of gross profit to Refining Margin, Refining Margin adjusted for FIFO Impact (in millions and on per total throughput barrel basis) and Direct operating expenses, excluding major turnaround expenses, per total throughput barrel.



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017
Net sales	$	1,857		$	1,386		$	5,139		$	4,148
Cost of materials and other	1,544			1,114			4,315			3,524
Direct operating expenses (exclusive of depreciation and amortization expenses as reflected below)	85			120			272			308
Depreciation and amortization	33			32			98			97
Gross profit	195			120			454			219
Add:
Direct operating expenses (exclusive of depreciation and amortization expenses as reflected below)	85			120			272			308
Depreciation and amortization	33			32			98			97
Refining margin	313			272			824			624
FIFO impact, (favorable) unfavorable	(3		)	(15		)	(45		)	1
Refining margin adjusted for FIFO impact	$	310		$	257		$	779		$	625



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Total throughput barrels per day	218,906	213,606	208,092	221,336
Days in the period	92	92	273	273
Total throughput barrels	20,139,352	19,651,752	56,809,116	60,424,728



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except for per throughput barrel data)	2018		2017		2018		2017
Refining margin	$	313	$	272	$	824	$	624
Divided by: total throughput barrels	20		20		57		60
Refining margin per total throughput barrel	$	15.54	$	13.81	$	14.50	$	10.32



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except for per throughput barrel data)	2018		2017		2018		2017
Refining margin adjusted for FIFO impact	$	310	$	257	$	779	$	625
Divided by: total throughput barrels	20		20		57		60
Refining margin adjusted for FIFO impact per total throughput barrel	$	15.41	$	13.05	$	13.71	$	10.33

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	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except for per throughput barrel data)	2018		2017		2018		2017
Direct operating expenses (exclusive of depreciation and amortization)	$	85	$	120	$	272	$	308
Major turnaround expenses	1		22		1		37
Direct operating expenses exclusive of major turnaround expenses	$	84	$	98	$	271	$	271
Divided by: total throughput barrels	20		20		57		60
Direct operating expenses, excluding major turnaround expenses, per total throughput barrel	$	4.17	$	5.02	$	4.77	$	4.49

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Liquidity and Capital Resources

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

We believe that our cash flows from operations and existing cash and cash equivalents, along with borrowings, as necessary, under the Amended and Restated ABL Credit Facility and the $150 million intercompany credit facility, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next 12 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. There have been no material changes in liquidity from our 2017 Form 10-K. The Partnership was in compliance with all covenants under its debt instruments as of September 30, 2018.

Cash and Other Liquidity

As of September 30, 2018, we had cash and cash equivalents of $398 million, $394 million available under our ABL Credit Facility and $150 million available under the intercompany credit facility for total liquidity of $754 million as of September 30, 2018.

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. Product yield is the percentage of refined products that is produced from crude oil and other feedstocks. Major turnaround expenses are expensed when incurred.

The following table summarizes our total actual capital expenditures for the nine months ended September 30, 2018 and current estimated capital expenditures for the full year 2018 by major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:



	September 30, 2018						Full Year 2018 Estimate
(In millions)	Maintenance		Growth		Total		Maintenance	Growth	Total
CVR Refining	$	39	$	11	$	50	$67 - 72	$13 - 18	$80 - 90

Our estimated capital expenditures are subject to change due to unanticipated changes in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries. We may also accelerate or defer some capital expenditures from time to time.

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Cash Flows

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



	Nine Months Ended September 30,
(In millions)	2018			2017
Net cash flow provided by (used in):
Operating activities	$	514		$	314
Investing activities	(49		)	(67		)
Financing activities	(241		)	(1		)
Net increase in cash and cash equivalents	$	224		$	246

Cash Flows Provided by Operating Activities

Net cash flows provided by operating activities for the nine months ended September 30, 2018 were approximately $514 million. The positive cash flow from operating activities generated over this period was primarily driven by net income of $439 million. Upon adjustment for non-cash depreciation and amortization of $101 million, net income was reduced by an increase of $26 million in trade working capital during the first nine months of 2018.

Cash Flows Used In Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2018 was $49 million compared to $67 million for the nine months ended September 30, 2017. Cash flows related to investing activities decreased primarily as a result of lower capital expenditures of $16 million in the nine months ended September 30, 2018 partially offset by a return of capital from our joint ventures of $1 million.

Cash Flows Used in Financing Activities

Net cash used in financing activities was $241 million and $1 million, respectively, for the nine months ended September 30, 2018 and 2017. The net cash used in financing activities for the nine months ended September 30, 2018 was primarily attributable to distributions to common unit holders of $239 million. There were no distributions for the nine months ended September 30, 2017.

As of and for the nine months ended September 30, 2018, there were no borrowings or repayments under the Amended and Restated ABL Credit Facility or under the intercompany credit facility.

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Forward-Looking Statements

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


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


•	statements relating to future financial or operational performance, future distributions, future capital sources and capital expenditures; and


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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we 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 under Part I — Item 1A. “Risk Factors” in the 2017 Form 10-K. Such factors include, among others:


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


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


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


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


•	the effects of transactions involving forward and derivative instruments;


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


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


•	the level of competition from other petroleum refiners;


•	changes in our credit profile;


•	potential operating hazards from accidents, fire, severe weather, tornadoes, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime at our facilities or those of our suppliers or customers;


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


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


•	the seasonal nature of our business;


•	our dependence on significant customers and the creditworthiness and performance by counterparties;


•	our potential inability to obtain or renew permits;

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•	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 and other matters beyond our control;


•	the risk of security breaches;


•	our lack of asset diversification;


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


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


•	the overall demand for hydrocarbon products, fuels and other refined products;


•	existing and proposed laws and regulations, including but, not limited to those relating to climate change, alternative energy or other fuel sources;


•	the price, availability and acceptance of alternative fuels and alternative fuel vehicles;


•	our ability to produce products and fuels that meet our customers’ unique and precise specifications;


•	rulings, judgments or settlements in litigation, tax or legal or regulatory matters;


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


•	the success of our acquisition and expansion strategies;


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


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


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


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


•	our indebtedness;


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


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


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


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


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


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


•	risks relating to our relationships with CVR Energy;


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


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


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

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


•	instability and volatility in the capital and credit markets;


•	our ability to produce or deliver products and fuels that meet current or future quality standards or product and fuel specifications; and


•	our ability to recover under our insurance policies for damages or losses in full or at all.

All forward-looking statements contained in this Report only speak as of the date of this Report. We undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events, except to the extent required by law.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes to our market risks as of September 30, 2018 and for the three and nine months ended September 30, 2018 from the risks discussed in Part II, Item 7A of our 2017 Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2018, we have evaluated, under the direction of our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based upon and as of the date of that evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting 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, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

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, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 11 ("Commitments and Contingencies") to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain litigation, legal and administrative proceedings and environmental matters.

Item 1A. Risk Factors

There have been no material changes from the risk factors previously disclosed in the “Risk Factors” section of our 2017 Form 10-K.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit Number		Exhibit Description
10.1*		CVR Energy, Inc. Change in Control and Severance Plan approved September 12, 2018.
10.2*		CVR Refining, LP Performance-Based Bonus Plan approved September 12, 2018.
10.3*		Amendment to the Performance Unit Agreement, dated September 17, 2018, by and between CVR Energy, Inc. and David L. Lamp.
31.1*		Rule 13a-14(a)/15d-14(a) Certification of President and Chief Executive Officer.
31.2*		Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer.
31.3*		Rule 13a-14(a)/15d-14(a) Certification of Chief Accounting Officer and Corporate Controller.
32.1†		Section 1350 Certification of President and Chief Executive Officer, Executive Vice President and Chief Financial Officer and the Chief Accounting Officer and Corporate Controller.
101*		The following financial information for CVR Refining, LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 formatted in XBRL (“Extensible Business Reporting Language”) includes: (i) Condensed Consolidated Balance Sheets (unaudited), (ii) Condensed Consolidated Statements of Operations (unaudited), (iii) Condensed Consolidated Statement of Changes in Partners’ Capital (unaudited), (iv) Condensed Consolidated Statements of Cash Flows (unaudited), and (v) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail.


*	Filed herewith.


†	Furnished 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

October 25, 2018	By:	/s/ TRACY D. JACKSON
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 25, 2018	By:	/s/ MATTHEW W. BLEY
		Chief Accounting Officer and Corporate Controller
		(Principal Accounting Officer)

CVR Refining, LP 10-Q