10-K 1 cvrr2016form10-kx12312016.htm 10-K Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________________________
Form 10-K
(Mark One)
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2016
OR
OR
o
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
(State or Other Jurisdiction of
Incorporation or Organization)
37-1702463
(I.R.S. Employer
Identification No.)
2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of Principal Executive Offices)
77479
(Zip Code)
Registrant's Telephone Number, including Area Code:
(281) 207-3200
_____________________________________________________________
          Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common units representing limited partner interests
The New York Stock Exchange
          Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ        No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes o        No þ
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 or 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    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.
Large accelerated filer o
Accelerated filer þ
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller reporting company)          
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes o        No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2016 (the last business day of the registrant’s second fiscal quarter) was $341,397,079. Common units of the registrant held by each executive officer and director and by each entity or person that, to the registrant’s knowledge, owned 10% or more of the registrant’s outstanding common units as of June 30, 2015 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of possible affiliate status is not necessarily a conclusive determination for other purposes.
Indicate the number of units outstanding of each of the registrant's classes of common units, as of the latest practicable date.
Class
Outstanding at February 14, 2017
Common units representing limited partner interests
147,600,000 units
 



TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 

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GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Annual Report on Form 10-K for the year ended December 31, 2016 (this "Report").
2022 Notes — $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022, which were issued by Refining LLC and Coffeyville Finance on October 23, 2012 and fully and unconditionally guaranteed by the Partnership and each of Refining LLC's domestic subsidiaries other than Coffeyville Finance.
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.

Amended and Restated ABL Credit Facility — Our senior secured asset based revolving credit facility with a group of lenders and Wells Fargo, as administrative agent and collateral agent.

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

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

bpd — Abbreviation for barrels per day.

bpcd — Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by the total number of days in the year (365 or 366 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.

Coffeyville Finance — Coffeyville Finance Inc., a wholly owned subsidiary of Refining LLC and an indirect wholly-owned subsidiary of the Partnership.

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.

CRLLC — Coffeyville Resources, LLC, a wholly-owned subsidiary of CVR Energy.

CRPLLC — Coffeyville Resources Pipeline, LLC.

CRRM — Coffeyville Resource Refining & Marketing, LLC, a wholly-owned subsidiary of Refining LLC and indirect wholly-owned subsidiary of the Partnership.

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

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

CVR Refining — CVR Refining, LP and its subsidiaries.


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CVR Refining GP — CVR Refining GP, LLC.

distillates — Primarily diesel fuel, kerosene and jet fuel.

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

EPA — The United States Environmental Protection Agency.

Excel Pipeline — Excel Pipeline LLC.

Exchange Act — Securities Exchange Act of 1934, as amended.

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.

FIFO — First-in, first-out.

GAAP — U.S. generally accepted accounting principles.

general partner — CVR Refining GP, 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 CHS Inc.'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.

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

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

intercompany credit facility — A $250.0 million senior unsecured revolving credit facility between CRLLC and Refining LLC.

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

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

natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and 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.

Partnership — CVR Refining and its subsidiaries.

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.

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refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

Refining LLC — CVR Refining, LLC, a wholly-owned subsidiary of the Partnership.

RFS — Renewable Fuel Standard of the EPA.

RINs — Renewable fuel credits, known as renewable identification numbers.

SEC — Securities and Exchange Commission.

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

sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

spot market — A market in which commodities are bought and sold for cash and delivered immediately.

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, which closed
on May 20, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).

Velocity — Velocity Central Oklahoma Pipeline LLC.

Vitol — Vitol Inc.

Vitol Agreement — The Amended and Restated Crude Oil Supply Agreement between Vitol and CRRM.

VPP — Velocity Pipeline Partners, LLC.

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.

Wells Fargo — Wells Fargo Bank, National Association.

WRC — Wynnewood Refining Company, LLC, the owner of the Wynnewood, Oklahoma refinery and related assets with a rated capacity of 70,000 bpcd.

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

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

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



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PART I

Item 1.    Business

Overview

CVR Refining, LP and, unless the context otherwise requires, its subsidiaries ("CVR Refining," the "Partnership," "we," "us," or "our") is an independent downstream energy limited partnership with refining and related logistics assets that operates in the mid-continent region. Our common units are listed on the New York Stock Exchange ("NYSE") under the symbol "CVRR."

We are a petroleum refiner and own 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 rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oils (within its rated capacity of 70,000 bpcd). The combined crude capacity represents approximately 22% of the region's refining capacity. In addition, we also control and operate supporting logistics assets including (i) approximately 340 miles of active owned and leased pipelines, (ii) approximately 150 crude oil transports, (iii) a network of strategically located crude oil gathering tank farms, (iv) approximately 6.4 million barrels of owned and leased crude oil storage, and (v) over 4.5 million barrels of combined refined products and feedstocks storage capacity. The strategic location of our refineries, combined with our supporting logistics assets, provide us with a significant crude oil cost advantage relative to our competitors. Furthermore, our Coffeyville refinery located in southeast Kansas and the Wynnewood refinery located 65 miles south of Oklahoma City, Oklahoma, are approximately 100 miles and 130 miles, respectively, from the crude oil hub at Cushing, Oklahoma ("Cushing"), and have access to inland domestic and Canadian crude oils that are priced based on the price of WTI. During the year ended December 31, 2016, the crude oil consumed at the refineries was price advantaged to WTI.

Our refineries' complexity allows us to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery's ability to process lower quality crude oil and feedstocks in an economic manner. Our two refineries' capacity weighted average complexity is 13.0. As a result of key investments in our refining assets and the addition of process units to comply with gasoline quality regulations, both of the refinery's complexities have increased. Our Coffeyville refinery's complexity score is 13.3, and our Wynnewood refinery's complexity score is 12.6. Our high complexity provides us the flexibility to increase our refining margin over comparable refiners with lower complexities. We have achieved significant increases in our refinery crude throughput rates over historical levels. As a result of the increasing complexities, we are capable of processing a variety of crudes, including WTS, WTI, sweet and sour Canadian, and locally gathered crudes.

For the year ended December 31, 2016, our Coffeyville refinery's product yield included gasoline (51%), diesel fuel (primarily ultra-low sulfur diesel) (42%), and pet coke and other refined products such as natural gas liquids ("NGLs") (propane and butane), slurry, sulfur and gas oil (7%). Our Wynnewood refinery's product yield included gasoline (53%), diesel fuel (primarily ultra-low sulfur diesel) (35%), asphalt (5%), jet fuel (4%) and other products (3%) (slurry, sulfur and gas oil, and specialty products such as propylene and solvents).

Our logistics assets have grown substantially since 2005. We have grown our crude oil gathering system capacity from 7,000 bpd in 2005 to over 70,000 bpd currently. The gathering system allows us to gather crude oil that is purchased from independent crude oil producers in Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, which serves our two refineries. During 2016, we gathered approximately 71,000 bpd of price-advantaged crudes from our gathering area. The system has field offices in Bartlesville and Pauls Valley, Oklahoma, Plainville and Winfield, Kansas and Denver, Colorado. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. In aggregate, these crudes have been sourced at a discount to WTI because of our proximity to the sources of crude oil, existing logistics infrastructure and quality differences. We also have 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow us to supply price-advantaged Canadian crude to our refineries. We also have contracted capacity on the Pony Express and White Cliffs pipelines, which both became in-service during 2015. Both the Pony Express and White Cliffs pipelines originate in Colorado and extend to Cushing.


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In addition to our gathering system, we own (i) a 170,000 bpd pipeline system that transports crude oil from our Broome Station facility to our Coffeyville refinery, (ii) approximately 1.5 million barrels of crude oil storage capacity that supports the gathering system and our Coffeyville refinery, (iii) approximately 0.9 million barrels of crude oil storage capacity at our Wynnewood refinery and (iv) approximately 1.5 million barrels of crude oil storage capacity in Cushing. We also lease additional crude oil storage capacity of approximately (v) 2.2 million barrels in Cushing, (vi) 0.2 million barrels in Duncan, Oklahoma and (vii) 0.1 million barrels at our Wynnewood refinery. The Duncan storage supports our Wynnewood refinery while the Cushing storage supports both our Wynnewood and Coffeyville refineries.

For the fiscal years ended December 31, 2016, 2015 and 2014, we generated net sales of $4.4 billion, $5.2 billion and $8.8 billion, respectively, and operating income of $77.8 million, $361.7 million and $207.2 million, respectively.

Our History

Our Coffeyville refining business was operated as a small component of Farmland Industries, Inc. ("Farmland") until March 3, 2004, the date on which CRLLC completed the acquisition of these assets and the adjacent nitrogen fertilizer plant now operated by CVR Partners through a bankruptcy court auction.

On June 24, 2005, our Coffeyville refinery and related businesses (as well as the adjacent nitrogen fertilizer plant now operated by CVR Partners), were acquired by Coffeyville Acquisition LLC ("CALLC").

On October 26, 2007, CVR Energy completed its initial public offering and its common stock was listed on the NYSE under the symbol "CVI." CVR Energy was formed as a wholly-owned subsidiary of CALLC in September 2006 in order to complete the initial public offering of the businesses acquired by CALLC. At the time of its initial public offering, CVR Energy operated our business and indirectly owned all of the limited partner interests in CVR Partners. In April 2011, CVR Partners completed its initial public offering. CVR Partners' common units are listed on the NYSE under the symbol "UAN." As of December 31, 2016, CVR Energy indirectly owns the general partner and approximately 34% of the outstanding common units of CVR Partners.

On December 15, 2011, CRLLC acquired all of the issued and outstanding shares of WEC. The assets acquired included a 70,000 bpcd rated capacity refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of storage tanks.

In May 2012, an affiliate of Icahn Enterprises L.P. ("IEP") acquired a majority of CVR Energy's common stock. As of December 31, 2016, IEP and its affiliates owned approximately 82% of CVR Energy's outstanding common stock.

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 of the Initial Public Offering, CRLLC contributed its wholly-owned subsidiaries and logistics assets to Refining LLC in October 2012, and CVR Refining Holdings, LLC ("CVR Refining Holdings"), a subsidiary of CRLLC and an indirect wholly-owned subsidiary of CVR Energy, contributed Refining LLC to us on December 31, 2012.

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, resulting in gross proceeds to us of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of IEP. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unit, resulting in gross proceeds to us of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." In connection with the Initial Public Offering, we paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs.

We have two types of partnership interests outstanding:

common units representing limited partner interests, a portion of which we sold in the Initial Public Offering and which are listed on the NYSE; and

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

Immediately 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 IEP, representing approximately 3% of all outstanding limited partner interests) and CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests.


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On May 20, 2013, we completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a 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 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.” In connection with the Transactions, we paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs.

We utilized net 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. We did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC.

Immediately following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding limited partner interests (including common units held by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximating 71% of all outstanding limited partner interests.

On June 30, 2014, we completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. We paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. We utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.

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

On August 2, 2016, an affiliate of IEP sold 250,000 common units of CVR Refining. As a result of this transaction, CVR Refining GP and its affiliates collectively own 69.99% of CVR Refining's outstanding common units. Pursuant to CVR Refining's partnership agreement, in certain circumstances, CVR Refining GP has the right to purchase all, but not less than all, of CVR Refining common units held by unaffiliated unit holders at a price not less than their then-current market price, as calculated pursuant to the terms of such partnership agreement (the “Call Right”). Pursuant to the terms of the partnership agreement, because CVR Refining GP and its affiliates’ holdings were reduced to less than 70.0% of CVR Refining's outstanding common units, the ownership threshold for the application of such Call Right was permanently reduced from 95% to 80%. Accordingly, if at any time CVR Refining GP and its affiliates own more than 80% of CVR Refining common units, it will have the right, but not the obligation, to exercise such Call Right.

As of December 31, 2016, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, which holds a non-economic general partner interest.


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Organizational Structure and Related Ownership

The following chart illustrates our organizational structure as of the date of this Report. cvrr2016orgchart01.jpg



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Crude and Feedstock Supply

Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, our Coffeyville refinery crude oil slate consists of a blend of mid-continent domestic grades, various Canadian medium and heavy sours, and North Dakota Bakken and other similarly sourced crudes. While crude oil has constituted over 90% of our Coffeyville refinery's total throughput over the last five years, other feedstock inputs include normal butane, natural gasoline, alkylation feeds, naphtha, gas oil and vacuum tower bottoms.

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. Historically most of the Wynnewood refinery's crude oil has been acquired domestically, mainly from Texas and Oklahoma, but it can also access and process various light and medium Canadian grades.

Crude oil is supplied to our refineries through our wholly-owned gathering system and by pipeline. We have continued to increase the number of barrels of crude oil supplied through our crude oil gathering system in 2016 and it now has the capacity of supplying over 70,000 bpd of crude oil to our refineries. For the year ended December 31, 2016, the gathering system supplied approximately 41% and 34% of the Coffeyville and Wynnewood refineries' crude oil demand, respectively. Locally produced crude oils are delivered to the refineries at a discount to WTI, and although sometimes slightly heavier and more sour, offer good economics to the refineries. These crude oils are light and sweet enough to allow us to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining our target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of our proprietary gathering system are delivered to Cushing by various pipelines, including the Keystone and Spearhead pipelines, and subsequently to our Broome Station facility via the Plains pipeline. Beginning in May 2015 and November 2015, our contracted capacity includes the Pony Express and White Cliffs pipelines, respectively. From the Broome Station facility, crude oil is delivered to our Coffeyville refinery via our own 170,000 bpd pipeline system. Crude oils are delivered to the Wynnewood refinery by three separate pipelines, and received into storage tanks at terminals located at or near the refinery.

For the year ended December 31, 2016, our Coffeyville refinery's crude oil supply blend was comprised of approximately 84.3% light sweet crude oil, 14.7% heavy sour crude oil and 1% light/medium sour crude oil. For the year ended December 31, 2016, our Wynnewood refinery's crude oil supply blend was comprised of approximately 98.2% light sweet crude oil and approximately 1.8% light/medium sour crude oil. The light sweet crude oil supply blend includes our locally gathered crude oil.

The Coffeyville refinery is connected to the mid-continent natural gas liquids commercial hub of Conway, Kansas by the inbound Enterprise Pipeline Blue Line. Natural gas liquids feedstock supplies such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition, Coffeyville's proximity to Conway provides access to the natural gas liquid and liquid petroleum gas fractionation and storage capabilities as well as the commercial markets available at Conway.

Crude Oil Supply Agreement

On August 31, 2012, CRRM and Vitol entered into 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, 2017.

Refining Process

Coffeyville Refinery. Our Coffeyville refinery is a 115,000 bpcd rated capacity facility with operations including fractionation, catalytic cracking, hydrotreating, reforming, coking, isomerization, alkylation, sulfur recovery and propane and butane recovery. Our Coffeyville refinery benefits from significant refining unit redundancies, which include two crude oil distillation and vacuum towers, three sulfur recovery units and four hydrotreating units. These redundancies allow us to continue to receive and process crude oil even if one tower requires unplanned maintenance without having to shut down the entire refinery in the case of a major unit turnaround. In addition, our Coffeyville refinery has a redundant supply of hydrogen pursuant to our feedstock and shared services agreement with CVR Partners. Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil into products such as gasoline, diesel, kerosene, propane, butane, sulfur, heavy oil and petroleum coke. During the year ended December 31, 2016, our Coffeyville refinery processed approximately 124,200 bpd and 8,500 bpd of crude oil and feedstocks and blendstocks, respectively. These throughput rates for 2016 reflect the second phase of the major scheduled turnaround completed in the first quarter of 2016.


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Wynnewood Refinery. Our Wynnewood refinery is a 70,000 bpcd rated capacity facility with operations including fractionation, cracking, hydrotreating, hydrocracking, reforming, solvent deasphalting, alkylation, sulfur recovery and propane and butane recovery. Similar to our Coffeyville refinery, our Wynnewood refinery benefits from unit redundancies, including two crude oil distillation and vacuum towers and four hydrotreating units. 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) into products such as gasoline, jet fuel, kerosene, propane, butane, propylene, sulfur, solvents, heavy oil and asphalt. During the year ended December 31, 2016, our Wynnewood refinery processed approximately 73,900 bpd and 2,600 bpd of crude oil and feedstocks and blendstocks, respectively.

Marketing and Distribution

We focus our Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity to the refinery and pipeline access. Coffeyville also has access to the Rocky Mountain area. Coffeyville engages in rack marketing, which is the supply of product through tanker trucks directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on the refined products distribution systems of Magellan and NuStar. Coffeyville also makes bulk sales (sales into third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up into North Dakota.

The Wynnewood refinery ships its finished product via pipeline, railcar, and truck. It focuses its efforts in the southern portion of the Magellan system which covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in the opposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S. Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail.

Customers

Customers for our refined products primarily include retailers, railroads and farm cooperatives and other refiners/marketers in Group 3 of the PADD II region because of their relative proximity to our refineries and pipeline access. We sell bulk products to long-standing customers at spot market prices based on a Group 3 basis differential to prices quoted on the New York Mercantile Exchange ("NYMEX"), which are reported by industry market-related indices such as Platts and Oil Price Information Service.

We also have a rack marketing business supplying product through tanker trucks directly to customers located in proximity to our Coffeyville and Wynnewood refineries, as well as to customers located at throughput terminals on refined products distribution systems run by Magellan and NuStar. Rack sales are at posted prices that are influenced by competitor pricing and Group 3 spot market differentials. Additionally, our Wynnewood refinery supplies jet fuel to the U.S. Department of Defense. In addition, our Coffeyville refinery sells a by-product of its refining operations, petroleum coke, to an affiliate, CVR Partners, pursuant to a multi-year agreement. For the year ended December 31, 2016, our two largest customers accounted for approximately 15% and 10% of our net sales while approximately 54% of our net sales were made to our ten largest customers.

Competition

We compete primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refineries provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors. We primarily compete against five refineries operated in the mid-continent region. In addition to these refineries, we compete against trading companies, as well as other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the Gulf Coast and the Texas panhandle region. Our competition also includes branded, integrated and independent oil refining companies, such as Phillips 66, HollyFrontier, CHS Inc., Valero and Flint Hills Resources.


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Seasonality

Our business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel is higher during the planting and harvesting seasons. As a result, our results of operations for the first and fourth calendar quarters are generally lower compared to our results for the second and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products can impact the demand for gasoline and diesel fuel. The demand for asphalt is also seasonal and is generally higher during the months of March through October.

Environmental Matters

Our businesses 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 products, and the characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact our business and operations by imposing:

restrictions on operations or the need to install enhanced or additional controls;

the need to obtain and comply with permits, licenses and authorizations;

requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and

specifications for the products marketed by us, primarily gasoline and diesel fuel.

Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimate impact on our business 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.

The principal environmental risks associated with our businesses are outlined below with additional details included in Part I, Item 1A, Risk Factors and Part II, Item 8, Note 11 ("Commitments and Contingencies") of this Report.

The Federal Clean Air Act

The federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect our operations both directly and indirectly. Direct impacts may occur through the federal Clean Air Act's permitting requirements and/or emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects our operations by extensively regulating the air emissions of sulfur dioxide ("SO2"), volatile organic compounds, nitrogen oxides and other substances, including those emitted by mobile sources, which are direct or indirect users of our products.

Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to our operations in order to comply. If new controls or changes to operations are needed, the costs could be material. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to comply and/or permit our facilities to produce products that meet applicable requirements.


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The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at our petroleum operations when regulations change or we add new equipment or modify our existing equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants ("NESHAP"), New Source Performance Standards ("NSPS") and New Source Review/Prevention of Significant Deterioration ("PSD"). We have incurred, and may be required to make substantial capital expenditures to attain or maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future.

On September 12, 2012, the U.S. Environmental Protection Agency (the "EPA") published in the Federal Register final revisions to its NSPS for process heaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the portions of the rule relating to process heaters and flares were stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissions of SO2 from flares, as well as require certain work practice and monitoring standards for flares. We do not believe that the costs of complying with the rule will be material.

On August 14, 2012, the EPA sent both the Wynnewood and Coffeyville refineries letters regarding the EPA's 2012 enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations signaling the agency's intention to begin a national enforcement program to conduct compliance evaluations and take enforcement actions against petroleum refining companies that operate flares that are not in compliance with standards articulated in the Enforcement Alert. The Enforcement Alert identified new standards that refiners are required to meet for flaring combustion efficiency. The EPA entered into consent decrees with several refining companies. Because the EPA has not specifically told us that our operations are not in compliance, we cannot say with certainty whether or when we may become an enforcement target under this initiative.

Refer to Part II, Item 8, Note 11 ("Commitments and Contingencies") of this Report for further discussion of recent environmental matters related to the Clean Air Act including the "Flood, Crude Oil Discharge and Insurance" and certain "Environmental, Health and Safety ("EHS") Matters," such as the "Coffeyville Second Consent Decree," "Wynnewood Clean Air Act Compliance" and other compliance evaluations.

The Federal Clean Water Act

The federal Clean Water Act ("CWA") and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect our operations. Direct impacts occur through the CWA's permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load of pollutants that may be released to a particular water body based on its use. In addition, water resources are becoming and in the future may become scarcer, and many refiners, including CRRM and WRC, are subject to restrictions on their ability to use water in the event of low availability conditions. Both CRRM and WRC have contracts in place to receive water during certain water shortage conditions, but these conditions could change over time if water becomes scarce.

Release Reporting

The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. Our refineries periodically have excess emission events from flaring and other planned and unplanned start up, shutdown and malfunction events. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act. If we fail to timely or properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.

Fuel Regulations

Tier 2, Low Sulfur Fuels.  In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Our refineries are in compliance with the EPA's low sulfur gasoline and diesel fuel standards.


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Tier 3.  In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no more than ten parts per million of sulfur on an annual average basis. Refineries must be in compliance with the more stringent emission standards by January 1, 2017; however, compliance with the rule is extended until January 1, 2020 for approved small volume refineries and small refiners. In June 2016, because it exceeded the EPA’s specified throughput limit for a “small volume refinery,” the Wynnewood refinery became disqualified as a “small volume refinery.” Therefore, the Wynnewood refinery’s compliance deadline was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.

Mobile Source Air Toxic II Emissions 

In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. The MSAT II projects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost of approximately $48.3 million and $89.0 million, excluding capitalized interest, by CRRM and WRC, respectively.

Renewable Fuel Standards 

Refer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 11 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of the "Renewable Fuel Standards."

Greenhouse Gas Emissions

Refer to Part I, Item 1A, Risk Factors, Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows, of this Report for further discussion of the Greenhouse Gas ("GHG") Emissions regulations.

RCRA

Our operations are subject to the Resource Conservation and Recovery Act ("RCRA") requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances. Refer to Part II, Item 8, Note 11 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" for further discussion of "RCRA Compliance Matters."

Waste Management.  There are two closed hazardous waste units at the Coffeyville refinery and eight other hazardous waste units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood refinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care.

Impacts of Past Manufacturing.  The 2004 Consent Decree that CRRM signed with the EPA and the Kansas Department of Health and Environment (the "KDHE") required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which required investigation and interim remediation projects. In December 2016, the Coffeyville refinery submitted a post-closure permit application to KDHE to complete closure of former hazardous waste management units at the Coffeyville refinery and perform corrective action at the site. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. The Phillipsburg terminal continues to implement interim measures to address the investigation’s findings. Further remediation, if ordered necessary by EPA or the state, will be based on the results of the investigation. The Wynnewood refinery operates under a RCRA permit. A RCRA facility investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, the Oklahoma Department of Environmental Quality ("ODEQ") and WRC have entered into a Consent Order requiring further investigations of groundwater conditions and enhancements of existing remediation systems. The Wynnewood refinery has completed the groundwater investigation and ODEQ has approved our corrective action recommendations.

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The anticipated investigation and remediation costs through 2020 were estimated, as of December 31, 2016, to be as follows:
Facility
Site
Investigation
Costs
 
Capital
Costs
 
Total Operation &
Maintenance
Costs
Through 2020
 
Total
Estimated
Costs
Through 2020
 
(in millions)
Coffeyville Refinery
$
0.2

 
$

 
$
1.0

 
$
1.2

Phillipsburg Terminal
0.5

 

 
0.7

 
1.2

Wynnewood Refinery
0.2

 

 
1.1

 
1.3

Total Estimated Costs
$
0.9

 
$

 
$
2.8

 
$
3.7


These estimates are based on current information and could increase or decrease as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2017, we will spend approximately $6.5 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and at the Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $2.1 million in 2016 associated with related remediation.

Financial Assurance

We are required under the 2004 Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010 agreement between CRRM, Coffeyville Resources Terminal, LLC, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $3.6 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.2 million for estimated costs to close regulated hazardous waste management units at the Coffeyville refinery. Additional self-funded financial assurance of approximately $4.9 million and $2.5 million is required by our post-closure care obligations and the 2004 Consent Decree for clean-up costs at the Coffeyville refinery and Phillipsburg terminal, respectively. The $3.6 million bond amount is reduced each year based on actual expenditures for corrective actions and the letter of credit and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.2 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.

Environmental Remediation

Under the CERCLA, 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 Oil Pollution Act of 1990 generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.

As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material. Refer to Part II, Item 8, Note 11 ("Commitments and Contingencies"), "Flood, Crude Oil Discharge and Insurance" of this Report for discussion of the environmental remediation associated with the discharge of crude oil on July 1, 2007 at the Coffeyville refinery.

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Environmental Insurance

We are covered by CVR Energy's site pollution legal liability insurance policy with an aggregate limit of $51.0 million per pollution condition, subject to a self-insured retention of $1.0 million. The policy includes business interruption coverage, subject to a 5-day waiting period deductible. This insurance expires on March 1, 2017 and is expected to be renewed without any material changes in terms. The policy insures any location owned, leased, rented or operated by CVR Refining, including the Coffeyville refinery and the Wynnewood refinery. The policy insures certain pollution conditions at or migrating from a covered location, certain waste transportation and disposal activities and business interruption.

In addition to the site pollution legal liability insurance policy, we benefit from umbrella and excess casualty insurance policies maintained by CVR Energy having an aggregate and occurrence limit of $300.0 million, subject to a self-insured retention and deductible of $5.0 million. This insurance provides coverage due to named perils for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. The casualty insurance policies, including umbrella and excess policies, expire on March 1, 2017 and are expected to be renewed or replaced by insurance policies containing materially equivalent sudden and accidental pollution coverage with no reduction in limits.

The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies contains discovery requirements, reporting requirements, exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.

Safety, Health and Security Matters

We are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act ("OSHA") and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.

We operate a comprehensive safety, health and security program, with participation by employees at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and consider improvements in our management systems.

Refer to Part II, Item 8, Note 11 ("Commitments and Contingencies"), "Wynnewood Refinery Incident" of this Report for further discussion of OSHA matters related to the Wynnewood refinery boiler explosion.

Employees

As of December 31, 2016, we employed 968 direct employees. These employees are covered by health insurance, disability and retirement plans established by CVR Energy. We believe that our relationship with our employees is good.

As of December 31, 2016, (i) the Coffeyville refinery employed 327 of our employees, about 70% of whom are covered by a collective bargaining agreement with five unions of the Metal Trades Department of the AFL-CIO ("Metal Trade Unions"), which expires in March 2019, (ii) we had 268 employees who work in crude transportation, about 32% of whom are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("United Steelworkers"), which expires in March 2019 and automatically renews on an annual basis unless a written notice is received sixty days in advance of the relevant expiration date, and (iii) the Wynnewood refinery employed 323 of our employees, about 58% of whom are covered by a collective bargaining agreement with the International Union of Operating Engineers, which expires in June 2017.

We also rely on the services of employees of CVR Energy and its subsidiaries pursuant to a services agreement among us, CVR Energy and our general partner. Additionally, the Partnership's general partner manages the Partnership's operations and activities as specified in the partnership agreement and had 14 employees as of December 31, 2016. For more information on these agreements, refer to Part II, Item 8, Note 14 ("Related Party Transactions") of this Report.


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Available Information

Our website address is www.cvrrefining.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after the electronic filing or furnishing of these reports is made with the Securities and Exchange Commission (the "SEC"). In addition, our Corporate Governance Guidelines, Codes of Ethics and Charters of the Audit Committee and Compensation Committee of the Board of Directors of our general partner are available on our website. These guidelines, policies and charters are also available in print without charge to any unitholder requesting them. We do not intend for information contained in our website to be part of this Report.




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Item 1A.    Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this Report.

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In such cases, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Inherent in Our Business

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash (which is defined as Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for 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) each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The board of directors of our general partner may at any time, for any reason, change our cash distribution policy or decide not to make any distribution. The amount of cash we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is directly dependent upon the margins we generate. Please see "— The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our profitability and our ability to pay distributions to unitholders" below.

The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our earnings and our ability to pay distributions to unitholders.

Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices tightens, our earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry margins may cause a decline in our results of operations, since the margin between refined product prices and crude oil and other feedstock prices may decrease below the amount needed for us to generate net cash flow sufficient for our needs. The effect of changes in crude oil prices on our results of operations therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, or a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, could have a significant negative impact on our earnings, results of operations and ability to pay distributions to unitholders.

Our profitability is also impacted by our ability to purchase crude oil at a discount to benchmark crude oils, such as WTI, as we do not produce any crude oil and must purchase all of the crude oil we refine. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Adverse changes in crude oil differentials can adversely impact refining margins, earnings and cash flows. In addition, our purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of our proximity to the sources, existing logistics infrastructure and quality differences. Any change in the sources of our crude oil, infrastructure or logistical improvements or quality differences could result in a reduction of our historical discount to WTI and may result in a reduction of our cost advantage.

Refining margins are also impacted by domestic and global refining capacity. Downturns in the economy reduce the demand for refined fuels and, in turn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel production capacity. Excess capacity can adversely impact refining margins, earnings and cash flows. The Arabian Gulf and Far East regions added refining capacity in 2015 and 2016.

We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline projects in 2014 expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage.


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Volatile prices for natural gas and electricity also affect our manufacturing and operating costs. Natural gas and electricity prices have been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which may be affected by items that do not fully impact net income in a given quarter. We may have working capital changes as well as extraordinary capital expenditures and major maintenance expenses in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Capital Spending." While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution with respect to such quarter. As a result, we may make cash distributions during periods when we report losses and may not make cash distributions during periods when we report net income.

The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business which is volatile and seasonal.

Historically, our business performance has been volatile and seasonal. For instance, our results of operations for the second and third quarters are generally higher than our results of operations for the first and fourth quarters, as demand for gasoline products increases due to higher highway traffic and road construction work during the summer months, and demand for diesel fuel decreases somewhat due to decreased agricultural activity in the winter. We expect that our future business performance will be more volatile and seasonal, and that our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all.

Our general partner's current policy is to distribute an amount equal to all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

Our refining business faces significant risks due to physical damage hazards, environmental liability risk exposure and unplanned or emergency partial or total plant shutdowns resulting in business interruptions. We could incur potentially significant costs to the extent there are unforeseen events which cause property damage and a material decline in production which are not fully insured. The commercial insurance industry engaged in underwriting energy industry risk is specialized and there is finite capacity; therefore, the industry may limit or curtail coverage, may modify the coverage provided or may substantially increase premiums in the future.

If any of our production plants, logistics assets, key pipeline operations serving our plants, or key suppliers sustains a catastrophic loss and operations are shutdown or significantly impaired, it would have a material adverse impact on our operations, financial condition and cash flows. Operations at either or both of the refineries could be curtailed, limited or completely shut down for an extended period of time as the result of one or more unforeseen events and circumstances, which may not be within our control, including:

major unplanned maintenance requirements;

catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire or natural disasters, including floods, windstorms and other similar events;

labor supply shortages or labor contract disputes that result in a work stoppage or slowdown;


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cessation or suspension of a plant or specific operations dictated by environmental authorities; and

an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.

We have sustained losses over the past ten-year period at our refineries, which are illustrative of the types of risks and hazards that exist. These losses or events resulted in costs assumed by us that were not fully insured due to policy retentions or applicable exclusions. These events included the Coffeyville refinery flood in June 2007; the fire in the Coffeyville refinery fluid catalytic cracking unit ("FCCU") in December 2010; a hydrocracker unit fire at the Wynnewood refinery in December 2010; a boiler explosion at the Wynnewood refinery in September 2012; a FCCU outage at the Coffeyville refinery in July/August 2013; and a isomerization unit fire at the Coffeyville refinery in July 2014.

Currently, we are insured under CVR Energy's casualty, environmental, property and business interruption insurance policies. The property and business interruption coverage has a combined policy limit of $1.25 billion for each occurrence. The property and business interruption policies insure real and personal property, including property located at our Coffeyville and Wynnewood refineries and our related crude gathering and logistics assets. There is potential for a common occurrence to impact both the CVR Partners' nitrogen fertilizer plant in Coffeyville, Kansas and the Coffeyville refinery, in which case the insurance limits and applicable sub-limits would apply to all damages combined. Under this insurance program there is a $2.5 million property damage retention for property, except there is a $10.0 million retention for refinery property. For a business interruption loss, the insurance program has up to a 45-day waiting period for any one occurrence. In addition, the insurance policies contain a schedule of sub-limits which apply to certain specific perils or areas of coverage. Sub-limits which may be of importance depending on the nature and extent of a particular insured occurrence are: flood, earthquake, contingent business interruption insuring key suppliers, pipelines and customers, debris removal, decontamination, demolition and increased cost of construction due to law and ordinance, and others. Policy conditions, limits and sub-limits could materially impact insurance recoveries and potentially cause us to assume losses which could impair earnings.

There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with the commercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums resulting from highly adverse loss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: industry wide losses, natural disasters, specific losses incurred by us and low or inadequate investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed due to highly adverse financial results we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity to adequately insure our risks for property damage or business interruption.

If we are required to obtain our crude oil supply without the benefit of a crude oil supply agreement, our exposure to the risks associated with volatile crude oil prices may increase and our liquidity may be reduced.

Since December 31, 2009, we have obtained substantially all of our crude oil supply for the Coffeyville refinery, other than the crude oil we gather, through the Vitol Agreement. The Vitol Agreement was amended and restated on August 31, 2012 to include the provision of crude oil intermediation services to our Wynnewood refinery. The agreement, which currently extends through December 31, 2017, minimizes the amount of in-transit inventory and mitigates crude oil pricing risk by ensuring pricing takes place close to the time the crude oil is refined and the yielded products are sold. If we were required to obtain our crude oil supply without the benefit of a supply intermediation agreement, our exposure to crude oil pricing risk may increase, despite any hedging activity in which we may engage, and our liquidity could be negatively impacted due to increased inventory, potential need to post letters of credit and negative impacts of market volatility. There is no assurance that we will be able to renew or extend the Vitol Agreement beyond December 31, 2017.


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Disruption of our ability to obtain an adequate supply of crude oil could reduce our liquidity and increase our costs.

In addition to the crude oil we gather locally in Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, we also purchased additional crude oil to be refined into liquid fuels in 2016. In 2016, our Coffeyville refinery purchased approximately 70,000 to 75,000 bpd of crude oil while our Wynnewood refinery purchased approximately 45,000 to 50,000 bpd of crude oil. Our Wynnewood refinery has historically acquired most of its purchased crude oil from Texas and Oklahoma with smaller amounts purchased from other regions. Our Coffeyville refinery and Wynnewood refinery obtained a portion of its non-gathered crude oil, approximately 25% and 0%, respectively, in 2016, from Canada. The actual amount of Canadian crude oil we purchase is dependent on market conditions and will vary from year to year. We are subject to the political, geographic, and economic risks attendant to doing business with Canada. Disruption of production for any reason could have a material impact on our ability to make distributions. In the event that one or more of our traditional suppliers becomes unavailable to us, we may be unable to obtain an adequate supply of crude oil, or we may only be able to obtain our crude oil supply at unfavorable prices. As a result, we may experience a reduction in our liquidity and our results of operations could be materially adversely affected.

If our access to the pipelines on which we rely for the supply of our crude oil and the distribution of our products is interrupted, our inventory and costs may increase and we may be unable to efficiently distribute our products.

If one of the pipelines on which either of the Coffeyville or Wynnewood refineries relies for supply of crude oil becomes inoperative, we would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase our costs and result in lower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, we would be required to keep refined fuels in inventory or supply refined fuels to our customers through an alternative pipeline or by additional tanker trucks, which could increase our costs and result in a decline in profitability.

The geographic concentration of our refineries and related assets creates an exposure to the risks of the local economy in which we operate and other local adverse conditions. The location of our refineries also creates the risk of increased transportation costs should the supply/demand balance change in our region such that regional supply exceeds regional demand for refined products.

As our refineries are both located in the southern portion of Group 3 of the PADD II region, we primarily market our refined products in a relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenues and our ability to make distributions. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil.

Should the supply/demand balance shift in our region as a result of changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the region exceeding demand, we may have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any.

If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected.

Pursuant to the Energy Independence and Security Act of 2007, the EPA has promulgated the RFS, which requires refiners to either blend "renewable fuels," such as ethanol and biodiesel, into their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels refineries like ours are obligated to blend into their finished petroleum products is adjusted annually. We are not able to blend the substantial majority of our transportation fuels and have 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 as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.


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On December 14, 2015, the EPA published in the Federal Register a final rule establishing the renewable fuel volume mandates for 2014, 2015 and 2016, and the biomass-based diesel mandate for 2017. On December 12, 2016, the EPA published in the Federal Register a final rule establishing the renewable fuel volume mandates for 2017 and the biomass-based diesel mandate for 2018. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authorities to lower the volumes, but its decision to do so for the 2014-2016 compliance years has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, the EPA has articulated a policy to incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs.

We cannot predict the future prices of RINs or waiver credits. The price of RINs has been extremely volatile and has increased over the last year. Additionally, 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 petroleum products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. However, the costs to obtain the necessary number of RINs and waiver credits could be material, if the price for RINs continues to increase. Additionally, because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions. If the demand for our transportation fuel decreases as a result of the use of increasing volumes of renewable fuels, increased fuel economy as a result of new EPA fuel economy standards, or other factors, the impact on our business could be material. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations and ability to pay distributions to our unitholders could be materially adversely affected.

We face significant competition, both within and outside of our industry. Competitors who produce their own supply of crude oil or other feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us.

The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined product markets. We may be unable to compete effectively with our competitors within and outside of our industry, which could result in reduced profitability. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore we do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. We do not have long-term arrangements (those exceeding more than a twelve-month period) for much of our output. Many of our competitors obtain significant portions of their crude oil and other feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

A number of our competitors also have materially greater financial and other resources than us. These competitors may have a greater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade 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 and may add additional competitive pressure on us.

In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for our products and our profitability.

Our indebtedness may affect our ability to operate our business, and may have a material adverse effect on our financial condition and results of operations.

We have incurred indebtedness and we may be able to incur significant additional indebtedness in the future. If new indebtedness is added to our current indebtedness, the risks described below could increase. Our level of indebtedness could have important consequences, such as:

limiting our ability to obtain additional financing to fund our working capital needs, capital expenditures, debt service requirements, acquisitions or other purposes;


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requiring us to utilize a significant portion of our cash flows to service our indebtedness, thereby reducing available cash and our ability to make distributions on our common units;

limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt;

limiting our ability to compete with other companies who are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;

restricting us from making strategic acquisitions, introducing new technologies or exploiting business opportunities;

restricting the way in which we conduct our business because of financial and operating covenants in the agreements governing our and our subsidiaries' existing and future indebtedness, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us;

exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries' debt instruments that could have a material adverse effect on our business, financial condition and operating results;

increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and

limiting our ability to react to changing market conditions in our industry and in our customers' industries.

In addition to our debt service obligations, our operations require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors.

In addition, we are and will be subject to covenants contained in agreements governing our present and future indebtedness. These covenants include, and will likely include, restrictions on certain payments (including restrictions on distributions to our unitholders), the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under our current credit agreements or debt instruments or future credit agreements.

Our debt agreements contain restrictions that will limit our flexibility in operating our business and our ability to make distributions to our unitholders.
Our debt facilities and instruments contain, and any instruments governing future indebtedness of ours would likely contain, a number of covenants that impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries' ability to, among other things:
incur additional indebtedness or issue certain preferred units;
pay distributions in respect of our units or make other restricted payments;
make certain payments on debt that is subordinated or secured on a junior basis;
make certain investments;
sell certain assets;
create liens on certain assets;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
enter into certain transactions with our affiliates; and
designate our subsidiaries as unrestricted subsidiaries.

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Any of these restrictions could limit our ability to plan for or react to market conditions and could otherwise restrict partnership activities. Any failure to comply with these covenants could result in a default under our debt facilities and instruments. Upon a default, unless waived, the lenders under our debt facilities and instruments would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our assets, and force us into bankruptcy or liquidation, subject to any applicable intercreditor agreements. In addition, a default under our debt facilities and instruments would trigger a cross default under our other agreements and could trigger a cross default under the agreements governing our future indebtedness. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.
Instability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition, results of operations and cash flows.

Our business, financial condition and results of operations could be negatively impacted by difficult conditions and volatility in the capital, credit and commodities markets and in the global economy. For example:

Although we believe we have sufficient liquidity under the Amended and Restated ABL Credit Facility and the intercompany credit facility to operate both the Coffeyville and Wynnewood refineries, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all.

Market volatility could exert downward pressure on the price of our common units, which may make it more difficult for us to raise additional capital and thereby limit our ability to grow, which could in turn cause the price of our common units to drop.

Market conditions could result in our significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us.

Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.

Changes in our credit profile may affect the way crude oil suppliers view our ability to make payments and may induce them to shorten the payment terms for our purchases or require us to post security prior to payment. Given the large dollar amounts and volume of our crude oil and other feedstock purchases, a burdensome change in payment terms may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.

Our commodity derivative contracts may limit our potential gains, exacerbate potential losses and involve other risks.

We enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected refined products production. However, our hedging arrangements may fail to fully achieve this objective for a variety of reasons, including our failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in margins. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;

accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery or our suppliers or customers;

the counterparties to our futures contracts fail to perform under the contracts; or

a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.


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As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions to unitholders.

Our commodity derivative activities could result in period-to-period volatility.

We do not apply hedge accounting to our commodity derivative contracts and, as a result, unrealized gains and losses are charged to our earnings based on the increase or decrease in the market value of the unsettled position. Such gains and losses are reflected in our income statement in periods that differ from when the underlying hedged items (i.e., gross margins) are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our operational performance.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market, and requires the Commodities Futures Trading Commission ("CFTC") to, among other things, institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The Dodd-Frank Act and implementing rules and regulations also require certain swap participants to comply with, among other things, certain margin requirements and clearing and trade-execution requirements in connection with certain derivatives activities. The rulemaking process is still ongoing, and we cannot predict the ultimate outcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral requirements for derivative instruments we may use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.

If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new rules and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to satisfy our debt obligations or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to satisfy our debt obligations.

Existing design, operational, and maintenance issues associated with acquisitions may not be identified immediately and may require unanticipated capital expenditures that could adversely impact our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Our due diligence associated with acquisitions may result in our assuming liabilities associated with unknown conditions or deficiencies, as well as known but undisclosed conditions and deficiencies, where we may have limited, if any, recourse for cost recovery. Such conditions and deficiencies may not become evident until sometime after cost recovery provisions, if any, have expired.

We must make substantial capital expenditures on our refineries and other facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows, and our ability to make distributions to unitholders, could be adversely affected.

Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to our existing facilities and equipment, could have a material adverse effect on our business, financial condition, results of operations or our ability to make distributions to our unitholders. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

denial or delay in obtaining regulatory approvals and/or permits;

unplanned increases in the cost of equipment, materials or labor;

disruptions in transportation of equipment and materials;


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severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of our vendors and suppliers;

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

market-related increases in a project's debt or equity financing costs; and/or

nonperformance or force majeure by, or disputes with, our vendors, suppliers, contractors or sub-contractors.

Our refineries have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. 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. For example, we incurred approximately $102.5 million associated with the turnaround for the Wynnewood refinery completed in December 2012. We incurred approximately $102.2 million associated with the first phase of the Coffeyville refinery turnaround completed in mid-November 2015 and approximately $31.5 million associated with second phase of the Coffeyville refinery turnaround completed during the first quarter of 2016. During the outage at our Coffeyville refinery as a result of the isomerization unit fire in the third quarter 2014, we accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million in turnaround expenses. During the FCCU outage at our Wynnewood refinery in the fourth quarter of 2014, we accelerated certain planned turnaround activities and incurred approximately $1.3 million in turnaround expenses. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. The next turnaround for the Wynnewood refinery will be performed as a two phase turnaround. The first phase is scheduled to begin in the second half of 2017, with the second phase to begin in the second half of 2018.

Any one or more of these occurrences noted above could have a significant impact on our business. If we were unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows and, as a result, our ability to make distributions.

Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.

Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.

In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition and profitability.

Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing and refining processes, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance. For a discussion of environmental laws and regulations and their impact on our business and operations, please see "Business — Environmental Matters."


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We could incur significant cost in cleaning up contamination at our refineries, terminals, and off-site locations.

Our businesses are subject to the occurrence of accidental spills, discharges or other releases of petroleum or hazardous substances into the environment. Past or future spills related to any of our current or former operations, including our refineries, pipelines, product terminals, or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under CERCLA, and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal.

The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and ability to pay distributions to our unitholders. In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for cleanup costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.

Three of our facilities, including our Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), and the Wynnewood refinery, have environmental contamination. We have assumed Farmland's responsibilities under certain administrative orders under the RCRA related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Coffeyville refinery has agreed to assume liability for contamination that migrated from the refinery onto the nitrogen fertilizer plant property while Farmland owned and operated the properties. At the Wynnewood refinery, known areas of contamination have been partially addressed but corrective action has not been completed (refer to "RCRA Compliance Matters" in Part II, Item 8, Note 11 ("Commitments and Contingencies") of this Report). If significant unknown liabilities are identified at or migrating from any of our facilities, that liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.

We may incur future liability relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the treatment, transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

We hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion of our operations is predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.

Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows.

The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our GHG emissions at our Coffeyville and Wynnewood refineries to the EPA. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new GHG emissions thresholds that determine when stationary sources, such as our refineries, must obtain permits under PSD and Title V programs of the federal Clean Air Act. Under the rule, facilities already subject to the PSD and Title V programs that increase their emissions of GHGs by a significant amount are required to undergo PSD review and to evaluate and implement air pollution control technology, known as "best available control technology," to reduce GHG emissions.


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In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate NSPS to regulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refining sector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. Therefore, we expect that the EPA will not be issuing NSPS to regulate GHG from the refineries at this time but that it may do so in the future.

During the State of the Union address in each of the last four years, President Obama indicated that the United States should take action to address climate change. It is possible, however, that the Trump administration and/or the new Congress will implement a new or modified policy with respect to climate change. If efforts to address climate change continue, at the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory GHG emission reduction, such as a nationwide cap-and-trade program. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.

In addition to potential federal legislation, a number of states have adopted regional GHG initiatives to reduce carbon dioxide and other GHG emissions. In 2007, a group of Midwest states, including Kansas (where our Coffeyville refinery is located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective. To date, Kansas has taken no meaningful action to implement the accord, and it is unclear whether Kansas intends to do so in the future.

Alternatively, the EPA may take further steps to regulate GHG emissions, although at this time it is unclear to what extent the EPA under its new Administrator will pursue climate change regulation. The implementation of EPA regulations and/or the passage of federal or state climate change legislation may result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.

In addition, climate change legislation and regulations may result in increased costs not only for our business but also users of our refined products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to cybersecurity risks and other cyber incidents resulting in disruption. 

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. We depend on information technology systems. In addition, we collect, process and retain sensitive and confidential customer information in the normal course of business. Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and systems, and those of our third-party service providers, could be vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, human errors, acts of vandalism or other events. Any disruption of our systems or security breach or event resulting in the misappropriation, loss or other unauthorized disclosure of confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation and liability, disrupt our business or otherwise affect our results of operations.


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Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us.

Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and cash flows.

Our business depends on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and our ability to pay distributions to our unitholders.

Both the Coffeyville and the Wynnewood refineries have a significant concentration of customers. Our five largest customers represented 40% of our net sales for the year ended December 31, 2016. One significant customer accounted for approximately 15% of our net sales. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or a significant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and our ability to pay distributions to our unitholders.

Our plans to expand our gathering and logistics assets, which assist us in reducing our costs and increasing our processing margins, may expose us to significant additional risks, compliance costs and liabilities.

We plan to continue to make investments to enhance the operating flexibility of our refineries and to improve our crude oil sourcing advantage through additional investments in our gathering and logistics assets. If we are able to successfully increase the effectiveness of our supporting gathering and logistics assets, we believe we will be able to enhance our crude oil sourcing flexibility and reduce related crude oil purchasing and delivery costs. However, the acquisition of infrastructure assets to expand crude oil gathering may expose us to risks in the future that are different than or incremental to the risks we face with respect to our refineries and existing gathering and logistics assets. The storage and transportation of liquid hydrocarbons, including crude oil and refined products, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect our operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit our operations, or claims of damages to property or persons resulting from our operations.

Any businesses or assets that we may acquire in connection with an expansion of our crude oil gathering could expose us to the risk of releasing hazardous materials into the environment. These releases would expose us to potentially substantial expenses, including cleanup and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Accordingly, if we do acquire any such businesses or assets, we could also incur additional expenses not covered by insurance which could be material.

More stringent trucking regulations may increase our costs and negatively impact our results of operations.

In connection with the trucking operations conducted by our crude gathering division, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Furthermore, from time to time, various legislative proposals are introduced, such as proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes will be enacted or the extent to which they will apply to us and our operations.

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The acquisition and expansion strategy of our business involves significant risks.

Our management will consider pursuing acquisitions and expansion projects in order to continue to grow and increase profitability. However, we may not be able to consummate such acquisitions or expansions, due to intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the failure to obtain requisite regulatory or other governmental approvals. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business.

In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:

unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business;

failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition;

strain on the operational and managerial controls and procedures of our business, and the need to modify systems or to add management resources;

difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;

assumption of unknown material liabilities or regulatory non-compliance issues;

amortization of acquired assets, which would reduce future reported earnings;

possible adverse short-term effects on our cash flows or operating results; and

diversion of management's attention from the ongoing operations of our business.

In addition, in connection with any potential acquisition or expansion project, we will need to consider whether a business we intend to acquire or expansion project we intend to pursue could affect our tax treatment as a partnership for federal income tax purposes. If we are otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect our treatment as a partnership for federal income tax purposes, we may elect to seek a ruling from the Internal Revenue Service ("IRS"). Seeking such a ruling could be costly or, in the case of competitive acquisitions, place us in a competitive disadvantage compared to other potential acquirers who do not need to seek such a ruling. If we are unable to conclude that an activity would not affect our treatment as a partnership for federal income tax purposes, and are unable or unwilling to obtain an IRS ruling, we may choose to acquire such business or develop such expansion project in a corporate subsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distribution to the unitholders and could likely cause a substantial reduction in the value of our common units.

Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and ability to pay cash distributions to our unitholders. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.

We are a holding company and depend upon our subsidiaries for our cash flow.

We are a holding company, and our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of distributions, tax sharing payments or otherwise. The ability of our subsidiaries to make any payments to us will depend on, among other things, their earnings, the terms of their indebtedness, tax considerations and legal restrictions.


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Our internally generated cash flows and other sources of liquidity may not be adequate for our capital needs.

Refining businesses such as ours are capital intensive, and working capital needs may vary significantly over relatively short periods of time. For instance, crude oil price volatility can significantly impact working capital on a week-to-week and month-to-month basis. If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations.

A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.

As of December 31, 2016, approximately 70% of the employees at the Coffeyville refinery, 58% of the employees at the Wynnewood refinery and 32% of the employees who work in crude transportation were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with five Metal Trades Unions (which covers union represented employees who work directly at the Coffeyville refinery) expires in March 2019. The collective bargaining agreement with United Steelworkers (which covers unionized employees who work in crude transportation) expires in March 2019, and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2017. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations, financial condition and cash flows.

Risks Inherent in Our Limited Partnership Structure and Common Units

The board of directors of our general partner has in place a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.

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. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. The board of directors of the general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions.

In addition, because of our distribution policy, our growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the outstanding common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders.

We rely on the executive officers of CVR Energy to manage certain aspects of our business and affairs pursuant to a services agreement, which CVR Energy can terminate at any time.

Our future performance depends to a significant degree upon the continued contributions of CVR Energy's senior management team. We have entered into a services agreement with our general partner and CVR Energy whereby CVR Energy has agreed to provide us with the services of its senior management team as well as accounting, legal, finance and other key back-office and mid-office personnel. CVR Energy can terminate this agreement at any time, subject to a 180-day notice period. The loss or unavailability to us of any member of CVR Energy's senior management team could negatively affect our ability to operate our business and pursue our business strategies. We do not have employment agreements with any of CVR Energy's officers and we do not maintain any key person insurance. In addition, CVR Energy may not continue to provide us the officers that are necessary for the conduct of our business or such provision may not be on terms that are acceptable. If CVR Energy elected to terminate the service agreement on 180 days' notice, we might not be able to find qualified individuals to serve as our executive officers within such 180-day period.


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In addition, pursuant to the services agreement we are responsible for a portion of the compensation expense of such executive officers according to the percentage of time such executive officers spend working for us. However, the compensation of such executive officers is set by CVR Energy, and we have no control over the amount paid to such officers. The services agreement does not contain any cap on the amounts we may be required to pay CVR Energy pursuant to this agreement.

Our general partner, an indirect wholly-owned subsidiary of CVR Energy, owes fiduciary duties to CVR Energy and its stockholders, and the interests of CVR Energy and its stockholders may differ significantly from, or conflict with, the interests of our public common unitholders.

Our general partner is responsible for managing us. Although our general partner has a duty to manage us in a manner that is not adverse to our interest, the fiduciary duties are specifically limited by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to CVR Energy and its stockholders. The interests of CVR Energy and its stockholders may differ from, or conflict with, the interests of our public common unitholders. In resolving these conflicts, our general partner may favor its own interests, the interests of CVR Refining Holdings, its sole member, or the interests of CVR Energy and holders of CVR Energy's common stock, including its majority stockholder, Icahn Enterprises, over our interests and those of our common unitholders.

The potential conflicts of interest include, among others, the following:

Neither our partnership agreement nor any other agreement requires the owners of our general partner, including CVR Energy, to pursue a business strategy that favors us. The affiliates of our general partner, including CVR Energy, have fiduciary duties to make decisions in their own best interests and in the best interest of holders of CVR Energy's common stock, including IEP, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners or CVR Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. There is no limitation on the amounts our general partner can cause us to pay it or its affiliates.

Our general partner controls the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner decides whether to retain separate counsel or others to perform services for us.

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

In addition, CVR Energy may compete with us, may in the future acquire assets which compete with our assets or may acquire assets such as refineries which we might otherwise have sought to acquire. We do not have any non-compete agreements or understandings with CVR Energy or any other agreement with CVR Energy regarding the allocation of corporate opportunities.

Our partnership agreement limits the liability and replaces the fiduciary duties of our general partner and restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement limits the liability and replaces the fiduciary duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:

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Our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or our common unitholders. Decisions made by our general partner in its individual capacity are made by CVR Refining Holdings as the sole member of our general partner, and not by the board of directors of our general partner. Examples include the exercise of the general partner's call right, its voting rights with respect to any common units it may own, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement.

Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it did not make such decisions in bad faith, meaning it believed that the decisions were adverse to our interest.

Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

Our partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.

CVR Energy has the power to appoint and remove our general partner's directors.

CVR Energy has the power to elect all of the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Our public unitholders do not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Furthermore, the goals and objectives of CVR Energy and IEP, as the indirect owners of our general partner, may not be consistent with those of our public unitholders.

Common units are subject to our general partner's call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. A unitholder may also incur a tax liability upon a sale of its common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right.


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Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner's directors and do not have sufficient voting power to remove our general partner without CVR Energy's consent.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right to elect our general partner or our general partner's board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen entirely by CVR Energy as the indirect owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we do not hold annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they have no practical ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished.

As of the date of this Report, CVR Energy indirectly owns approximately 66% of our common units, which means holders of common units other than CVR Energy will not be able to remove the general partner, under any circumstances, unless CVR Energy sells some of the common units that it owns or we sell additional units to the public. In addition, affiliates of IEP own approximately 3.9% of our common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to our unitholders.

Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, our pro rata portion of management compensation and overhead charged by CVR Energy in accordance with our services agreement. The services agreement does not contain any cap on the amount we may be required to pay pursuant to this agreement. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to the holders of our common units.

Unitholders may have liability to repay distributions.

In the event that: (i) we make distributions to our unitholders when our nonrecourse liabilities exceed the sum of (a) the fair market value of our assets not subject to recourse liability and (b) the excess of the fair market value of our assets subject to recourse liability over such liability, or a distribution causes such a result, and (ii) a unitholder knows at the time of the distribution of such circumstances, such unitholder will be liable for a period of three years from the time of the impermissible distribution to repay the distribution under Section 17-607 of the Delaware Act.

Likewise, upon the winding up of the partnership, in the event that (a) we do not distribute assets in the following order: (i) to creditors in satisfaction of their liabilities; (ii) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (iii) to partners for the return of their contribution; and finally (iv) to the partners in the proportions in which the partners share in distributions and (b) a unitholder knows at the time of such circumstances, then such unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-807 of the Delaware Act.


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Our general partner's interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owners of our general partner to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner.

If control of our general partner were transferred to an unrelated third party, the new owner of the general partner would have no interest in CVR Energy. We rely substantially on the senior management team of CVR Energy and have entered into a number of significant agreements with CVR Energy, including a services agreement pursuant to which CVR Energy provides us with the services of its senior management team. If our general partner were no longer controlled by CVR Energy, CVR Energy could be more likely to terminate the services agreement which it may do upon 180 days' notice.

Mr. Carl C. Icahn exerts significant influence over the Partnership and his interests may conflict with the interests of the Partnership's public unitholders.

CVR Energy indirectly owns our general partner and approximately 66% of our common units. CVR Energy has the right to appoint and replace all of the members of the board of directors of our general partner at any time.

Mr. Carl C. Icahn indirectly controls approximately 82% of the voting power of CVR Energy's capital stock and, by virtue of such stock ownership in CVR Energy, is able to elect and appoint all of the directors of CVR Energy. This gives Mr. Icahn the ability to control and exert substantial influence over CVR Energy. As a result of such control of CVR Energy, he is able to control the Partnership, including:

business strategy and policies;

mergers or other business combinations;

the acquisition or disposition of assets;

future issuances of common units or other securities;

incurrence of debt or obtaining other sources of financing; and

the Partnership's distribution policy and the payment of distributions on the Partnership's common units.

CVR Energy provides us with the services of its senior management team as well as accounting, legal, finance and other key back-office and mid-office personnel pursuant to a services agreement which it can terminate at any time subject to a 180-day notice period. We cannot predict whether CVR Energy will terminate the services agreement and, if so, what the economic effect of termination would be. CVR Energy also has the right under our partnership agreement to sell our general partner at any time to a third party, who would be able to replace our entire board of directors. Finally, while CVR Energy currently owns the majority of our common units, its current owners are under no obligation to maintain their ownership interest in us, which could have a material adverse effect on us.

Mr. Icahn's interests may not always be consistent with the Partnership's interests or with the interests of the Partnership's public unitholders. Mr. Icahn and entities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliates of Mr. Icahn. To the extent that conflicts of interest may arise between the Partnership and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner adverse to the Partnership or its public unitholders.


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We may issue additional common units and other equity interests without the approval of our unitholders, which would dilute the existing ownership interests of our unitholders.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

the proportionate ownership interest of unitholders immediately prior to the issuance will decrease;

the amount of cash distributions on each unit will decrease;

the ratio of our taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit will be diminished; and

the market price of the common units may decline.

In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

Units eligible for future sale may cause the price of our common units to decline.

Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. This could also impair our ability to raise additional capital through the sale of our equity interests. As of the date of this Report, there were 147,600,000 common units outstanding. Of this amount, CVR Energy indirectly owns approximately 66% of our common units and public security holders own approximately 34% of our common units.

In addition, under our partnership agreement, our general partner and its affiliates have the right to cause us to register their units under the Securities Act and applicable state securities laws. In connection with the Initial Public Offering, we entered into a registration rights agreement with an affiliate of IEP, CVR Refining Holdings and CVR Refining Holdings Sub, LLC, pursuant to which we may be required to register the sale of the common units they hold under the Securities Act and applicable state securities laws. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by an affiliate of IEP, CVR Refining Holdings or CVR Refining Holdings Sub, LLC.

As a publicly traded partnership we qualify for, and are relying on, certain exemptions from the NYSE's corporate governance requirements.

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE's corporate governance requirements, including:

the requirement that a majority of the board of directors of our general partner consist of independent directors;

the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

Our general partner's board of directors has not established and does not currently intend to establish a nominating/corporate governance committee. Additionally, we could avail ourselves of the additional exemptions available to publicly traded partnerships listed above at any time in the future. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.


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Tax Risks

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced, likely causing a substantial reduction in the value of our common units.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Current law requires us to derive at least 90% of our annual gross income from specific activities to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. We may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement.

Although we do not believe, based upon our current operations, that we will be treated as a corporation for U.S. federal income tax purposes, a change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity level taxation. We may in the future enter into new activities or businesses. If our legal counsel were to be unable to opine that gross income from any such activity or business will count toward satisfaction of the 90% gross income, or qualifying income, requirement to be treated as a partnership for U.S. federal income tax purposes, we could seek a ruling, if available, from the IRS that gross income we earn from any such activity or business will be qualifying income. There can be no assurance, however, that the IRS would issue a favorable ruling under such circumstances. If we did not receive a favorable ruling, we could choose to engage in the activity or business through a corporate subsidiary, which would subject the income related to such activity or business to entity-level taxation. Except to the extent that we in the future request a ruling regarding the qualifying nature of our income from a particular activity or business, we do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, or if we were otherwise subject to entity-level taxation, we would pay U.S. federal income tax on all of our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in CVR Refining common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including CVR Refining, or an investment in CVR Refining common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which CVR Refining relies for its treatment as a partnership for U.S. federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017.  We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes. However, there are no assurances that the Final Regulations will not be revised to take a position that is contrary to our interpretation of the current law.

Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for CVR Refining to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. CVR Refining is unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in CVR Refining common units.


36


Several states currently subject partnerships to entity level taxation. Specifically, we are subject to the Texas franchise tax. Such taxes reduce our cash available for distribution to our unitholders. Other states are evaluating proposals to subject partnerships to entity level taxation through the imposition of income, franchise or other forms of taxation.  Imposition of these or similar taxes by any other state in which we do business will further reduce our cash available for distribution to our unitholders and could cause a substantial reduction in the value of our common units. We are unable to predict whether any of these or other proposals will ultimately be enacted.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be materially and adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

Except to the extent that we, in the future, request a ruling regarding the qualifying nature of our income, we have not and do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

A unitholder's share of our income is taxable for U.S. federal income tax purposes even if the unitholder does not receive any cash distributions from us.

Our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute. A unitholder's allocable share of our taxable income is taxable to the unitholder, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on the unitholder's share of our taxable income, even if no cash distributions are received from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.


37


The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same common unit will be counted only once. Our sponsor directly and indirectly owns more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could result in a termination of us as a partnership for U.S. federal income tax purposes. While we would continue our existence as a Delaware limited partnership, a technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than one year of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby a publicly traded partnership that has technically terminated may request special relief that, if granted, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if our unitholders sell common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations promulgated under the Internal Revenue Code, referred to as "Treasury Regulations." A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could cause a substantial reduction in the value of our common units or result in audit adjustments to our unitholders' tax returns.


38


We prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of common units) may be considered as having disposed of the loaned common units. In that case, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, unitholders are likely to be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own or control property now or in the future, even if they do not live in any of those jurisdictions. We currently own assets and/or conduct business in the states of Arkansas, Colorado, Iowa, Kansas, Missouri, Nebraska, Oklahoma, Texas and South Dakota. These states, other than Texas and South Dakota, currently impose a personal income tax on individuals. These states, other than South Dakota, also impose income taxes on corporations and other entities. Unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all U.S. federal, state, local, and non-U.S. tax returns. Our counsel has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in our common units.


39


Item 1B.    Unresolved Staff Comments

There are no material unresolved written comments that were received from the SEC staff 180 days or more before the end of our fiscal year relating to our periodic or current reports under the Exchange Act.


40


Item 2.    Properties

The following table contains certain information regarding our principal properties:
Location
 
Acres
 
Own/Lease
 
Use
Coffeyville, KS
 
380
 
Own
 
Oil refinery and office buildings
Wynnewood, OK
 
400
 
Own
 
Oil refinery, office buildings, refined oil storage
Montgomery County, KS (Coffeyville Station)
 
20
 
Own
 
Crude oil storage
Montgomery County, KS (Broome Station)
 
20
 
Own
 
Crude oil storage
Cowley County, KS (Hooser Station)
 
80
 
Own
 
Crude oil storage
Cushing, OK
 
138
 
Own
 
Crude oil storage

Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas. We also have an administrative office in Kansas City, Kansas. The offices in Sugar Land and Kansas City are leased by CVR Energy and we will pay a pro rata share of the rent on those offices. We believe that our facilities, together with CVR Energy's leased facilities, are sufficient for our operating needs.

As of December 31, 2016, we own crude oil storage capacity of approximately (i) 1.5 million barrels supporting the gathering system and Coffeyville refinery, (ii) 0.9 million barrels at the Wynnewood refinery and (iii) 1.5 million barrels in Cushing, Oklahoma. We also lease additional crude oil storage capacity of approximately (iv) 2.2 million barrels in Cushing, (v) 0.2 million barrels in Duncan, Oklahoma and (vi) 0.1 million barrels at the Wynnewood refinery. In addition to crude oil storage, we own over 4.5 million barrels of combined refined products and feedstocks storage capacity.

We are party to a cross-easement agreement with CVR Partners so that both we and CVR Partners are able to access and utilize each other's land in Coffeyville in certain circumstances in order to operate our respective businesses in a manner to provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party's property. For more information on this cross-easement agreement, see Part III, Item 13 of this Report "Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy and CVR Partners."


41


Item 3.    Legal Proceedings

We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under "Business — Environmental Matters." We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits and proceedings described and referenced in Note 11 ("Commitments and Contingencies") to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Report. In accordance with Generally Accepted Accounting Principles ("GAAP"), we record a liability when it is both probable that a liability has been incurred and the amount of the loss 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. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

Item 4.    Mine Safety Disclosures

Not applicable.


42


PART II

Item 5.    Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common units are listed on the NYSE under the symbol "CVRR" and commenced trading on January 17, 2013. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common units for our two most recent fiscal years:
2016
High
 
Low
First Quarter
$
20.25

 
$
10.17

Second Quarter
13.25

 
7.33

Third Quarter
11.25

 
5.50

Fourth Quarter
11.00

 
6.45


2015
High
 
Low
First Quarter
$
21.18

 
$
13.37

Second Quarter
22.59

 
18.02

Third Quarter
21.23

 
17.30

Fourth Quarter
22.74

 
18.26


Holders of Record

As of February 14, 2017, there were 10 holders of record of our common units. Because many of our common units are held by brokers and other institutions on behalf of holders, we are unable to estimate the total number of beneficial owners represented by these record holders.

Cash Distribution Policy

Our general partner's current policy 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 (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, (iv) 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 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. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low earnings, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in our operating performance and earnings caused by fluctuations in our refining margins. Such variations may be significant. The board of directors of our general partner may change the foregoing distribution policy at any time and the partnership agreement does not require us to make distributions at all.

Our ability to make distributions is limited by our Amended and Restated ABL Credit Facility and the indenture governing the 2022 Notes. See Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for a discussion of those limitations.


43


The following is a summary of cash distributions paid to our unitholders during the year ended December 31, 2015 for the respective quarters to which the distributions relate:

 
December 31, 2014
 
March 31, 2015
 
June 30, 2015
 
September 30, 2015
 
Total Cash
Distributions
 Paid in 2015 
 
(in millions, except per unit data)
Amount paid to CVR Refining Holdings, LLC and affiliates
$
38.2

 
$
78.5

 
$
101.2

 
$
104.4

 
$
322.3

Amounts paid to non-affiliates
16.4

 
33.7

 
43.4

 
44.7

 
138.2

Total amount paid
$
54.6

 
$
112.2

 
$
144.6

 
$
149.1

 
$
460.5

Per common unit
$
0.37

 
$
0.76

 
$
0.98

 
$
1.01

 
$
3.12

Common units outstanding
147.6

 
147.6

 
147.6

 
147.6

 
 

No cash distributions were paid during 2016.

Unit Performance Graph

The following graph sets forth the cumulative return on our common units between January 17, 2013 and December 31, 2016, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy, Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. The graph assumes an investment of $100 on January 17, 2013 based on the closing unit price in our common units, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of distributions where applicable. The closing market price for our common units on December 31, 2016 was $10.40. The unit price performance shown on the graph is not intended to forecast and does not necessarily indicate future price performance.

COMPARISON OF CUMULATIVE TOTAL RETURN
BETWEEN JANUARY 17, 2013 AND DECEMBER 31, 2016
among CVR Refining, LP, Russell 2000 Index and a peer group
cvrr2016perform_chart.jpg
This performance graph shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.

 
Jan '13
 
Mar '13
 
Jun '13
 
Sep '13
 
Dec '13
 
Mar '14
 
Jun '14
 
Sep '14
 
Dec '14
CVR Refining, LP
100.00

 
138.48

 
125.71

 
109.41

 
100.61

 
105.69

 
117.62

 
113.83

 
84.00

Russell 2000 Index
100.00

 
106.87

 
109.78

 
120.60

 
130.69

 
131.75

 
133.99

 
123.73

 
135.30

Peer Group
100.00

 
120.45

 
98.15

 
88.06

 
125.78

 
117.54

 
115.11

 
121.97

 
121.16



44


 
Mar '15
 
Jun '15
 
Sep '15
 
Dec '15
 
Mar '16
 
Jun '16
 
Sep '16
 
Dec '16
CVR Refining, LP
105.85

 
96.82

 
106.24

 
110.12

 
70.27

 
45.08

 
51.02

 
60.50

Russell 2000 Index
140.70

 
140.84

 
123.62

 
127.58

 
125.12

 
129.38

 
140.58

 
152.42

Peer Group
155.24

 
151.09

 
152.70

 
148.45

 
117.11

 
92.37

 
104.10

 
134.23


Purchases of Equity Securities by the Issuer

We did not repurchase any of our common units during the fiscal quarter ended December 31, 2016.


45


Item 6.    Selected Financial Data

You should read the selected historical consolidated and combined financial data presented below in conjunction with, and the selected historical consolidated and combined financial data presented below is qualified in its entirety by reference to, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included elsewhere in this Report.

The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 2016, 2015 and 2014 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" as of December 31, 2016 and 2015 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financial statements have been audited by Grant Thornton LLP, our independent registered public accounting firm. The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the year ended December 31, 2013, the selected combined financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the year ended December 31, 2012, and the selected consolidated financial information presented below under the caption "Balance Sheet Data" at December 31, 2014, 2013 and 2012 is derived from our audited consolidated and combined financial statements that are not included in this Report.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
(in millions, except per unit data)
Statements of Operations Data
 
 
 
 
 
 
 
 
 
Net sales
$
4,431.3

 
$
5,161.9

 
$
8,829.7

 
$
8,683.5

 
$
8,281.7

Cost of materials and other
3,759.2

 
4,143.6

 
8,013.4

 
7,526.7

 
6,667.5

Direct operating expenses(1)
393.4

 
478.5

 
416

 
361.7

 
426.5

Flood insurance recovery

 
(27.3
)
 

 

 

Depreciation and amortization
126.3

 
128.0

 
120.9

 
113.9

 
107.1

Cost of sales
4,278.9

 
4,722.8

 
8,550.3

 
8,002.3

 
7,201.1

Selling, general and administrative expenses(1)
71.9

 
75.2

 
70.6

 
77.8

 
86.2

Depreciation and amortization
2.7

 
2.2

 
1.6

 
0.4

 
0.5

Operating income
77.8


361.7


207.2

 
603.0

 
993.9

Interest expense and other financing costs
(43.4
)
 
(42.6
)
 
(34.2
)
 
(44.1
)
 
(76.2
)
Interest income
0.1

 
0.4

 
0.3

 
0.4

 

Gain (loss) on derivatives, net
(19.4
)
 
(28.6
)
 
185.6

 
57.1

 
(285.6
)
Loss on extinguishment of debt

 

 

 
(26.1
)
 
(37.5
)
Other income (expense), net
0.2

 
0.3

 
(0.2
)
 
0.1

 
0.7

Income before income tax expense
15.3

 
291.2

 
358.7

 
590.4

 
595.3

Income tax expense

 

 

 

 

Net income
$
15.3

 
$
291.2

 
$
358.7

 
$
590.4

 
$
595.3

Available cash for distribution(2)
$
0.3

 
$
402.0

 
$
421.5

 
$
546.0

 
 
Net income subsequent to initial public offering (January 23, 2013 through December 31, 2013)
 
 
 
 


 
$
512.6

 
 
Net income per common unit – basic and diluted(3)
$
0.10

 
$
1.97

 
$
2.43

 
$
3.47

 
 
 
 
 
 
 
 
 
 
 
 
Weighted average common units outstanding:
 
 
 
 
 
 
 
 
 
Basic and Diluted
147.6

 
147.6

 
147.6

 
147.6

 
 


46


 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
(in millions)
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
314.1

 
$
187.3

 
$
370.2

 
$
279.8

 
$
153.1

Working capital(4)
313.7

 
297.5

 
503.6

 
656.0

 
380.9

Total assets(4)
2,331.9

 
2,189.0

 
2,410.7

 
2,525.3

 
2,246.2

Total debt, including current portion(4)
541.5

 
573.8

 
574.3

 
574.7

 
760.9

Total partners' capital/divisional equity
1,296.7

 
1,281.4

 
1,450.1

 
1,522.1

 
980.8

Cash Flow Data
 
 
 
 
 
 
 
 
 
Net cash flow provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
267.8

 
$
473.7

 
$
715.8

 
$
601.0

 
$
917.3

Investing activities
(107.9
)
 
(194.7
)
 
(191.2
)
 
(204.4
)
 
(119.8
)
Financing activities(5)
(33.1
)
 
(461.9
)
 
(434.2
)
 
(269.9
)
 
(647.1
)
Net cash flow
$
126.8

 
$
(182.9
)
 
$
90.4

 
$
126.7

 
$
150.4

 
 
 
 
 
 
 
 
 
 
Capital expenditures for property, plant and equipment
$
102.3

 
$
194.7

 
$
191.3

 
$
204.5

 
$
120.2

 

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

(2)
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 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. For the year ended December 31, 2013, available cash for distribution is calculated for the period beginning at the closing of our Initial Public Offering (January 23, 2013 through December 31, 2013).

(3)
We have omitted net income per unit for the year ended December 31, 2012 because we 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 year ended December 31, 2013 is calculated since the closing of the Initial Public Offering on January 23, 2013.

(4)
Prior period amounts have been retrospectively adjusted for Accounting Standard Update No. 2015-03, which requires that costs incurred to issue debt be presented in the balance sheet as a direct reduction from the carrying value of the debt.

(5)
Prior to December 31, 2012, Coffeyville Resources, LLC ("CRLLC") provided cash as necessary to support our operations and retained excess cash generated by our operations. Historical cash received, or paid by, CRLLC on our behalf has been recorded as net contributions from, or net distributions to, parent, respectively, as a component of divisional equity in our historical combined financial statements, and as a financing activity in our Combined Statements of Cash Flows. Net distributions to parent included in cash flows from financing activities were $651.6 million for the year ended December 31, 2012.



47


Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our consolidated financial statements and related notes included elsewhere in this Report.

Forward-Looking Statements

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

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

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

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

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under the section captioned "Risk Factors" and contained elsewhere in this Report. 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 consequences from accidents, fire, severe weather, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime;

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 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;

48



our dependence on significant customers;

our potential inability to obtain or renew permits;

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

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

the risk of security breaches;

our lack of asset diversification;

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

our ability to comply with employee safety laws and regulations;

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

the success of our acquisition and expansion strategies;

our reliance on CVR Energy's senior management team;

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

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

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

our indebtedness;

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

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

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

our limited operating history as a stand-alone entity;

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

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

risks relating to our relationships with CVR Energy;

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

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

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

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

instability and volatility in the capital and credit markets.

49



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.

Overview and Executive Summary

We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the Group 3 of the PADD II region of the United States. 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 of the Initial Public Offering, CRLLC contributed its wholly-owned subsidiaries and logistics assets described above to Refining LLC in October 2012, and CVR Refining Holdings, LLC ("CVR Refining Holdings"), a subsidiary of CRLLC and an indirect wholly-owned subsidiary of CVR Energy, contributed Refining LLC to us on December 31, 2012. Refer to Part I, Item 1, Business, of this Report for a detailed discussion of our business.

Our Initial Public Offering

On January 23, 2013, we completed our Initial Public Offering of 24,000,000 common units priced at $25.00 per unit. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units priced at $25.00 per unit. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." Immediately 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 IEP, 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 the outstanding 10.875% Second Lien Senior Secured Notes due 2017 (the "Old Second Lien Notes"), $160.0 million was 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 were 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.

Our Underwritten Offering

On May 20, 2013, we completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a 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 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."

We utilized net 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. We did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC.

Immediately following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding limited partner interests (including common units held by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 71% of all outstanding limited partner interests.


50


Our Second Underwritten Offering

On June 30, 2014, we completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. We paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. We utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.

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

IEP Sale of CVR Refining Units
       
On August 2, 2016, an affiliate of IEP sold 250,000 common units of CVR Refining. As a result of this transaction, CVR Refining GP and its affiliates collectively own 69.99% of CVR Refining's outstanding common units. Pursuant to CVR Refining's partnership agreement, in certain circumstances, CVR Refining GP has the right to purchase all, but not less than all, of CVR Refining common units held by unaffiliated unit holders at a price not less than their then-current market price, as calculated pursuant to the terms of such partnership agreement (the “Call Right”). Pursuant to the terms of the partnership agreement, because CVR Refining GP and its affiliates’ holdings were reduced to less than 70.0% of CVR Refining's outstanding common units, the ownership threshold for the application of such Call Right was permanently reduced from 95% to 80%. Accordingly, if at any time CVR Refining GP and its affiliates own more than 80% of CVR Refining common units, it will have the right, but not the obligation, to exercise such Call Right.

As of December 31, 2016, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, which holds a non-economic general partner interest.

Major Influences on Results of Operations

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

The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. Widespread expansion or upgrades of our competitors' facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. The petroleum business is also subject to the RFS, which requires it to either blend "renewable fuels" in with its transportation fuels or purchase RINs, in lieu of blending.

51



Refer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 11 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of RFS.
 
The cost of RINs for the years ended December 31, 2016, 2015 and 2014 was approximately $205.9 million, $123.9 million and $127.2 million, respectively. The price of RINs has been extremely volatile and has increased over the last year. The future cost of RINs is difficult to estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period.
  
In order to assess our operating performance, we compare our net sales, less cost of materials and other, 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 are 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 refining 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 refining 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 refining margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS price differential to WTI and the WCS price differential to WTI as both these differentials indicate the relative price of heavier, more sour, crude oil slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate. Our consumed crude oil cost discount to WTI for 2016 was $1.58 per barrel compared to consumed crude oil cost discounts of $1.12 per barrel in 2015 and $0.54 per barrel in 2014.

We produce a high volume of high value products, such as gasoline and distillates. 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 because the prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline expansions in recent years expanding the connectivity of Cushing and Permian Basin markets to the gulf coast along with lifting the crude oil export ban has resulted in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and could see a downward movement in refining margins as a result.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2016, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $11.7 million.


52


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 earnings. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory may have a major effect on our financial results from period to period.

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. During the outage at our Coffeyville refinery in the third quarter of 2014 as discussed further below, we accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014. The first phase of the Coffeyville refinery's most recent turnaround was completed in November 2015 at a total cost of approximately $101.5 million. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016 and we incurred $31.5 million of major scheduled turnaround expenses for the Coffeyville turnaround during 2016. During the outage at our Wynnewood refinery in the fourth quarter of 2014 as discussed further below, we accelerated certain planned turnaround activities and incurred approximately $1.3 million in turnaround expenses for the year ended December 31, 2014. The next turnaround scheduled for the Wynnewood refinery will be performed as a two-phase turnaround. The first phase is scheduled to begin in the second half of 2017, with the second phase to begin in the second half of 2018. Turnaround expenses associated with the first and second phase of the Wynnewood turnaround are estimated to be approximately $80.0 million to $100.0 million. Additionally, we expect to accelerate certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. Turnaround expenses associated with the hydrocracker are estimated to be approximately $15.0 million.

On July 29, 2014, our Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employee who was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System, which was directly caused by the fire. The refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the year ended December 31, 2014 were approximately $6.3 million.

We are covered by property damage insurance policies at the time of the incident, which had an associated deductible of $5.0 million for the Coffeyville refinery. We anticipate amounts in excess of the $5.0 million deductible related to the isomerization unit fire incident will be recoverable under the property insurance policies. The Consolidated Balance Sheets as of December 31, 2015 and 2014 included an insurance receivable related to prior year claims of approximately $1.2 million and $1.3 million, respectively, included in prepaid expenses and other current assets. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

During the fourth quarter of 2014, the FCCU at our Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at our Wynnewood refinery was significantly reduced. Additionally, we incurred approximately $8.5 million in costs to repair the FCCU for the year ended December 31, 2014, which were included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.

Agreements with Affiliates

CVR Energy and its subsidiaries are party to several agreements with CVR Partners and its subsidiary that govern the business relations among CVR Partners, CVR Energy and their subsidiaries and affiliates, and the general partner of CVR Partners. In connection with our Initial Public Offering in January 2013, some of the subsidiaries party to these agreements became subsidiaries of CVR Refining.


53


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, but not limited to, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iii) a raw water and facilities sharing agreement, which allocates raw water resources between the Coffeyville refinery and the nitrogen fertilizer plant; (iv) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners; (v) a cross-easement agreement, which grants easements to both parties for operational facilities, pipelines, equipment, access, and water rights; and (vi) an environmental agreement which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville refinery and the nitrogen fertilizer plant. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

CRRM and Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF") entered into a hydrogen purchase and sale agreement that is effective January 2017, pursuant to which, CRRM agrees to sell and deliver a committed hydrogen volume of 90,000 mscf per month, and CRNF agrees to purchase and receive the committed volume. CRNF also has the option to purchase excess volume of up to 60,000 mscf per month, or more upon mutual agreement, from CRRM, if available for purchase and priced pursuant to the agreement. The agreement has an initial term of 20 years and will be automatically extended following the initial term for additional successive five-year renewal term unless either party gives 180 days written notice. Refer to Part III, Item 13 of this Report for further discussion of the hydrogen purchase and sale agreement.

On September 19, 2016, CRPLLC, an indirect wholly-owned subsidiary of CVR Refining, entered into an agreement with Velocity related to their joint ownership of VPP. VPP will construct, own and operate a 12-inch crude oil pipeline with design capacity of approximately 65,000 barrel per day and with an estimated length of 25 miles with a connection to the Partnership's Wynnewood refinery and a trucking terminal at Lowrance, Oklahoma. CRPLLC holds a 40% interest in VPP and expects to contribute approximately $9.3 million to VPP during the pipeline construction, which is expected to be completed in the second quarter of 2017. Velocity holds a 60% interest in VPP, serves as the day-to-day operator of VPP and expects to contribute approximately $14.0 million. As of December 31, 2016, CRPLLC has contributed $5.6 million to VPP. On September 19, 2016, the Partnership also entered into a transportation agreement with VPP for an initial term of 20 years under which VPP will provide the Partnership with crude oil transportation services for crude oil purchased within a defined geographic area, and the Partnership entered into a terminalling services agreement with Velocity under which the Partnership will receive access to Velocity’s terminal in Lowrance, OK to unload and pump crude oil into VPP's pipeline for an initial term of 20 years.

In connection with the Initial Public Offering, we entered into a number of agreements with CVR Energy, including (i) a $250.0 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

On August 31, 2012, CRRM and Vitol entered into the Vitol Agreement. Under the Vitol Agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2017.


54


Factors Affecting Comparability

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons presented and discussed below.
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Share-based compensation(1)
 
4.9

 
9.3

 
8.0

(Gain) loss on derivatives, net
 
19.4

 
28.6

 
(185.6
)
Major scheduled turnaround expenses(2)
 
31.5

 
102.2

 
6.8

Flood insurance recovery(3)
 

 
(27.3
)
 

_______________________________________

(1)
Represents impact of share-based compensation awards.

(2)
Represents expense associated with major scheduled turnaround activities performed at our Coffeyville refinery ($31.5 million in 2016, $102.2 million in 2015 and $5.5 million in 2014) and our Wynnewood refinery (1.3 million in 2014).

(3)
Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery on June/July 2007. Refer to Part II, Item 8, Note 11 ("Commitments and Contingencies"), of this Report for further details.

Distributions to CVR Refining Unitholders

Refer to Part II, Item 5, "Cash Distribution Policy," of this Report for a summary of our distribution policy and the cash distributions paid to our unitholders during years ended December 31, 2016 and 2015.

55


Results of Operations

The period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. The following tables below provide an overview of our results of operations, relevant market indicators and key operating statistics for the years ended December 31, 2016, 2015 and 2014.

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

Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See " — Major Influences on 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 materials and other. Refining margin is a measurement calculated as the difference between net sales and cost of materials and other.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions)
Consolidated Statements of Operations Data
 
 
 
 
 
Net sales
$
4,431.3

 
$
5,161.9

 
$
8,829.7

Operating costs and expenses:
 
 
 
 
 
Cost of materials and other
3,759.2

 
4,143.6

 
8,013.4

Direct operating expenses(1)(2)
361.9

 
376.3

 
409.2

Major scheduled turnaround expenses
31.5

 
102.2

 
6.8

Depreciation and amortization
126.3

 
128.0

 
120.9

Cost of sales
4,278.9

 
4,750.1

 
8,550.3

Flood insurance recovery

 
(27.3
)
 

Selling, general and administrative expenses(1)
71.9

 
75.2

 
70.6

Depreciation and amortization
2.7

 
2.2

 
1.6

Operating income
77.8

 
361.7

 
207.2

Interest expense and other financing costs
(43.4
)
 
(42.6
)
 
(34.2
)
Interest income
0.1

 
0.4

 
0.3

Gain (loss) on derivatives, net
(19.4
)
 
(28.6
)
 
185.6

Other income (expense), net
0.2

 
0.3

 
(0.2
)
Income before income tax expense
15.3

 
291.2

 
358.7

Income tax expense

 

 

Net income
$
15.3

 
$
291.2

 
$
358.7

Gross profit(3)
$
152.4

 
$
439.1

 
$
279.4

Refining margin(4)
$
672.1

 
$
1,018.3

 
$
816.3

Adjusted EBITDA(5)
$
222.8

 
$
602.0

 
$
621.6

Available cash for distribution(6)
$
0.3

 
$
402.0

 
$
421.5




56


 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(dollars per barrel)
Key Operating Statistics
 
 
 
 
 
Per crude oil throughput barrel:
 
 
 
 
 
Gross profit(3)
$
2.10

 
$
6.23

 
$
3.90

Refining margin(4)
$
9.27

 
$
14.45

 
$
11.38

Direct operating expenses and major scheduled turnaround expenses(1)(2)
$
5.43

 
$
6.79

 
$
5.80

Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(7)
$
5.08

 
$
6.40

 
$
5.44

Barrels sold (barrels per day)(7)
211,643

 
204,708

 
209,669


 
Year Ended December 31,
 
2016
 
2015
 
2014
 
 
 
%
 
 
 
%
 
 
 
%
Refining Throughput and Production Data (bpd)
 
 
 
 
 
 
 
 
 
 
 
Throughput:
 
 
 
 
 
 
 
 
 
 
 
Sweet
177,256

 
84.8
 
176,097

 
86.0
 
179,059

 
86.2
Medium
2,525

 
1.2
 
2,460

 
1.2
 
2,022

 
1.0
Heavy sour
18,261

 
8.7
 
14,520

 
7.1
 
15,464

 
7.4
Total crude oil throughput
198,042

 
94.7
 
193,077

 
94.3
 
196,545

 
94.6
All other feedstocks and blendstocks
11,077

 
5.3
 
11,672

 
5.7
 
11,284

 
5.4
Total throughput
209,119

 
100.0
 
204,749

 
100.0
 
207,829

 
100.0
Production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
108,762

 
51.9
 
99,961

 
48.5
 
102,275

 
48.9
Distillate
85,092

 
40.6
 
85,953

 
41.7
 
87,639

 
41.9
Other (excluding internally produced fuel)
15,751

 
7.5
 
20,074

 
9.8
 
19,149

 
9.2
Total refining production (excluding internally produced fuel)
209,605

 
100.0
 
205,988

 
100.0
 
209,063

 
100.0
Product price (dollars per gallon):
 
 
 
 
 
 
 
 
 
 
 
Gasoline
$
1.34

 
 
 
$
1.61

 
 
 
$
2.53

 
 
Distillate
1.36

 
 
 
1.62

 
 
 
2.81

 
 


57


 
Year Ended December 31,
 
2016
 
2015
 
2014
Market Indicators (dollars per barrel)
 
 
 
 
 
West Texas Intermediate (WTI) NYMEX
$
43.47

 
$
48.76

 
$
92.91

Crude Oil Differentials:
 
 
 
 
 
WTI less WTS (light/medium sour)
0.85

 
(0.28
)
 
5.95

WTI less WCS (heavy sour)
13.95

 
13.20

 
18.48

NYMEX Crack Spreads:
 
 
 
 
 
Gasoline
15.42

 
19.89

 
17.29

Heating Oil
13.89

 
20.93

 
23.59

NYMEX 2-1-1 Crack Spread
14.66

 
20.41

 
20.44

PADD II Group 3 Product Basis:
 
 
 
 
 
Gasoline
(3.62
)
 
(2.12
)
 
(4.45
)
Ultra Low Sulfur Diesel
(0.92
)
 
(2.02
)
 
0.75

PADD II Group 3 Product Crack Spread:
 
 
 
 
 
Gasoline
11.82

 
17.76

 
12.84

Ultra Low Sulfur Diesel
12.96

 
18.91

 
24.34

PADD II Group 3 2-1-1
12.39

 
18.34

 
18.59

 

(1)
Our direct operating expenses and selling, general and administrative expenses for the years ended December 31, 2016, 2015 and 2014 are shown exclusive of depreciation and amortization (Refer to Part II, Item 8, Note 2 ("Summary of Significant Accounting Policies") of this report for further details.)

(2)
Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3)
Gross profit, a GAAP measure, is calculated as the difference between net sales and cost of materials and other, direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery and depreciation and amortization. Each of the components used in this calculation are taken directly from our Consolidated Statements of Operations. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.

(4)
Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of materials and other. 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 materials and other at which we are able to sell refined products. Each of the components used in this calculation (net sales and cost of materials and other) are taken directly from our Consolidated Statements of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput 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.


58


The calculation of refining margin and refining margin per crude oil throughput barrel for the years ended December 31, 2016, 2015 and 2014 is as follows:
 
Year Ended 
 December 31,
 
2016
 
2015
 
2014
 
(in millions)
Net Sales
$
4,431.3

 
$
5,161.9

 
$
8,829.7

Cost of materials and other
3,759.2

 
4,143.6

 
8,013.4

Direct operating expenses (exclusive of depreciation and amortization as reflected below)
361.9

 
376.3

 
409.2

Major scheduled turnaround expenses
31.5

 
102.2

 
6.8

Flood insurance recovery

 
(27.3
)
 

Depreciation and amortization
126.3

 
128.0

 
120.9

Gross Profit
152.4

 
439.1

 
279.4

Add:
 
 
 
 
 
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
361.9

 
376.3

 
409.2

Major scheduled turnaround expenses
31.5

 
102.2

 
6.8

Flood insurance recovery

 
(27.3
)
 

Depreciation and amortization
126.3

 
128.0

 
120.9

Refining Margin
$
672.1

 
$
1,018.3

 
$
816.3


 
Year Ended 
 December 31,
 
2016
 
2015
 
2014
Total crude oil throughput barrels per day
198,042

 
193,077

 
196,545

Days in the period
366

 
365

 
365

Total crude oil throughput barrels
72,483,372

 
70,473,105

 
71,738,925


 
Year Ended 
 December 31,
 
2016
 
2015
 
2014
 
(in millions, except for $ per barrel data)
Refining Margin
$
672.1

 
$
1,018.3

 
$
816.3

Divided by: crude oil throughput barrels
72.5

 
70.5

 
71.7

Refining Margin per crude oil throughput barrel
$
9.27

 
$
14.45

 
$
11.38


(5)
EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) 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 impact (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and Adjustment EBITDA), (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery.


59


We present Adjusted EBITDA because it is the starting point for our determination of available cash for distribution. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income (loss) or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enable investors to better understand our ability to make distributions to our common unitholders, help investors evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of net income (loss) to EBITDA and EBITDA to Adjusted EBITDA for the three months ended December 31, 2016 and the years ended December 31, 2016, 2015 and 2014:
 
Three Months Ended 
 December 31,
 
Year Ended December 31,
 
2016
 
2016
 
2015
 
2014
 
(in millions)
 
(unaudited)
Net income (loss)
$
(10.7
)
 
$
15.3

 
$
291.2

 
$
358.7

Add:
 
 
 
 
 
 
 
Interest expense and other financing costs, net of interest income
11.6

 
43.3

 
42.2

 
33.9

Income tax expense

 

 

 

Depreciation and amortization
33.4

 
129.0

 
130.2

 
122.5

EBITDA
34.3

 
187.6

 
463.6

 
515.1

Add:
 
 
 
 
 
 
 
FIFO impact (favorable) unfavorable(a)
(22.4
)
 
(52.1
)
 
60.3

 
160.8

Share-based compensation, non-cash

 

 
0.6

 
2.3

Loss on extinguishment of debt

 

 

 

Major scheduled turnaround expenses(b)

 
31.5

 
102.2

 
6.8

(Gain) loss on derivatives, net
14.6

 
19.4

 
28.6

 
(185.6
)
Current period settlements on derivative contracts(c)
1.2

 
36.4

 
(26.0
)
 
122.2

Flood insurance recovery(d)