S-1/A 1 d417501ds1a.htm AMENDMENT NO. 3 TO FORM S-1 Amendment No. 3 to Form S-1
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on January 8, 2013

Registration No. 333-184200

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

AMENDMENT NO. 3

TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

CVR Refining, LP

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware
  2911
  37-1702463
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

2277 Plaza Drive, Suite 500

Sugar Land, TX 77479

(281) 207-3200

(Address, Including Zip Code, and Telephone Number, Including

Area Code, of Registrant’s Principal Executive Offices)

John J. Lipinski

2277 Plaza Drive, Suite 500

Sugar Land, Texas 77479

(281) 207-3200

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

Mike Rosenwasser

E. Ramey Layne

 

Sean T. Wheeler

Keith Benson

Vinson & Elkins L.L.P.

666 Fifth Avenue, 26th Floor

New York, New York 10103

Tel: (212) 237-0000

Fax: (212) 237-0100

 

Latham & Watkins LLP

811 Main Street

Suite 3700

Houston, TX 77002

Tel (713) 546-5400

Fax (713) 546-5401

 

 

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this Registration Statement becomes effective.

 

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  ¨

   Accelerated filer  ¨    Non-accelerated filer  x    Smaller reporting company  ¨
      (Do not check if a smaller reporting company)   

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

  Amount to be
Registered(1)
  Proposed Maximum
Offering Price
Per Share(2)
 

Proposed Maximum
Aggregate

Offering  Price(1)(2)

 

Amount of

Registration Fee(3)

Common units representing limited partner interests

  23,000,000   $26.00   $598,000,000   $81,568

 

 

(1)   Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes additional common units that the underwriters have the option to purchase.
(2)   Estimated solely for the purpose of calculating the registration fee.
(3)   The Registrant previously paid $34,380 of the total registration fee in connection with the previous filing of this Registration Statement.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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Index to Financial Statements

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JANUARY 8, 2013

 

LOGO

CVR Refining, LP

20,000,000 Common Units

Representing Limited Partner Interests

 

 

This is our initial public offering. We are offering 20,000,000 common units. Prior to this offering, there has been no public market for our common units. We anticipate that the initial public offering price will be between $24.00 and $26.00 per common unit. Our common units have been approved for listing on the New York Stock Exchange under the symbol “CVRR.”

Icahn Enterprises, L.P. has indicated that it or its affiliates may purchase in this offering up to $100.0 million, or up to approximately 4,000,000 (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common units at the same price as the price to the public. The underwriters will not receive any underwriting discounts or commissions or structuring fees on any common units sold to Icahn Enterprises or its affiliates. The number of common units available for sale to the general public will be reduced to the extent Icahn Enterprises, L.P. or its affiliates purchase such common units. See “Underwriting” beginning on page 229.

We have granted the underwriters an option to purchase up to a maximum of 3,000,000 common units.

See “Risk Factors” on page 24 to read about factors you should consider before buying our common units. These risks include the following:

 

   

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

 

   

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

 

   

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. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

 

   

The board of directors or 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 pay any distributions at all.

 

   

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.

 

   

Our business depends on significant customers and the loss of one or 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.

 

   

Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

 

   

You will incur immediate and substantial dilution in net tangible book value per common unit.

 

   

Our tax treatment depends on our status as a partnership for 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 for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

   

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

The underwriters expect to deliver the common units to purchasers on or about                     , 2013.

 

      

Price to

Public

 

Underwriting
Discounts and Commissions(1)

    

Proceeds to
CVR Refining, LP

Per Common Unit

     $               $                  $            

Total(2)

     $               $                  $            

 

 

(1) Includes a structuring fee equal to 0.5% of the gross proceeds from this offering, including the gross proceeds from any exercise of the underwriters’ option to purchase additional units but excluding any proceeds from the sale of common units to Icahn Enterprises, L.P. or its affiliates, payable to Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc.
(2) Assumes Icahn Enterprises, L.P. and its affiliates have not purchased common units in this offering, for which the underwriters would not receive any underwriting discounts or commissions or structuring fees.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

Credit Suisse     Citigroup

 

 

Barclays   UBS Investment Bank   Jefferies
J.P. Morgan   Macquarie Capital   Simmons & Company International         

The date of this prospectus is                     , 2013.


Table of Contents
Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

 

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     24   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     52   

USE OF PROCEEDS

     54   

CAPITALIZATION

     55   

DILUTION

     56   

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     57   

HOW WE MAKE CASH DISTRIBUTIONS

     72   

SELECTED HISTORICAL AND UNAUDITED PRO FORMA COMBINED FINANCIAL AND OPERATING DATA

     73   

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     81   

INDUSTRY

     119   

BUSINESS

     125   

MANAGEMENT

     146   

COMPENSATION DISCUSSION AND ANALYSIS

     154   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     175   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     177   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     189   

DESCRIPTION OF THE COMMON UNITS

     197   

THE PARTNERSHIP AGREEMENT

     199   

UNITS ELIGIBLE FOR FUTURE SALE

     212   

MATERIAL TAX CONSEQUENCES

     214   

INVESTMENT IN CVR REFINING, LP BY EMPLOYEE BENEFIT PLANS

     228   

UNDERWRITING

     229   

LEGAL MATTERS

     235   

EXPERTS

     235   

WHERE YOU CAN FIND MORE INFORMATION

     235   

INDEX TO FINANCIAL STATEMENTS

     F-i   

ANNEX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF CVR REFINING, LP

     A-1   

ANNEX B—GLOSSARY OF SELECTED INDUSTRY TERMS

     B-1   

 

 

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

 

 

Through and including                     , 2013 (the 25th day after the date of this prospectus), all dealers effecting transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Trademarks, Trade Names and Service Marks

This prospectus includes trademarks belonging to CVR Energy, Inc., including COFFEYVILLE RESOURCES® and CVR Energy. This prospectus also contains trademarks, service marks, copyrights and trade names of other companies.

 

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Index to Financial Statements

Industry and Market Data

The data included in this prospectus regarding the refining industry, including trends in the market and our position and the position of our competitors within the refining industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information (including the reports and other information our competitors file with the Securities and Exchange Commission, which we did not participate in preparing and as to which we make no representation), as well as our good faith estimates, which have been derived from management’s knowledge and experience in the areas in which our business operates. Estimates of market size and relative positions in a market are difficult to develop and inherently uncertain. Accordingly, investors should not place undue weight on the industry and market share data presented in this prospectus.

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the combined historical and unaudited pro forma financial statements and related notes included elsewhere in this prospectus, before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $25.00 per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units. References in this prospectus to “CVR Refining, LP” as well as “we,” “our,” “us” or like terms when used in a historical perspective, refer to the petroleum refining and related logistics business of CVR Energy, Inc., (“CVR Energy”). When used in a present or future context, “Partnership,” “we,” “our,” “us” or like terms refer to CVR Refining, LP and its consolidated subsidiaries unless the context otherwise requires or where otherwise indicated. References to “CVR Refining GP” or “our general partner” refer to CVR Refining GP, LLC, which, following the closing of this offering, will be an indirect wholly-owned subsidiary of CVR Energy. References to “Coffeyville Resources” refer to Coffeyville Resources, LLC, a wholly-owned subsidiary of CVR Energy. References to “CVR Refining Holdings” refer to CVR Refining Holdings, LLC, a wholly-owned subsidiary of Coffeyville Resources. The transactions being entered into in connection with this offering are referred to herein as the “Transactions” and are described on page 8 of this prospectus. You should also see the “Glossary of Selected Industry Terms” contained in Annex B for definitions of some of the terms we use to describe our business and industry and other terms used in this prospectus.

Overview

We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the mid-continent region. We own two of only seven refineries in the underserved Group 3 of the PADD II region of the United States. We own and operate a 115,000 barrels per day (“bpd”) complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpd medium complexity crude oil refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oils (within its 70,000 bpd capacity). In addition, we also control and operate supporting logistics assets including approximately 350 miles of owned pipelines, over 125 owned crude oil transports, a network of strategically located crude oil gathering tank farms, and over 6.0 million barrels of owned and leased crude oil 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 and Wynnewood refineries are located approximately 100 miles and 130 miles, respectively, from the crude oil hub at Cushing, Oklahoma, and have access to inland domestic and Canadian crude oils that are priced based on the price of West Texas Intermediate crude oil (“WTI”). In the nine months ended September 30, 2012, the crude oil consumed at the refineries was at a discount to the price of WTI of $2.81 per barrel.

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 in an economic manner. Our two refineries’ capacity weighted average complexity is 11.5. As a result of key investments in our refining assets, our Coffeyville refinery’s complexity increased to 12.9 in 2012 from 10.3 in 2005. Our management team, which joined us in 2005 in connection with the Coffeyville refinery acquisition, has also achieved significant increases in this refinery’s crude oil throughput rate since the acquisition. Our Wynnewood refinery, which we acquired in December 2011, currently has a complexity of 9.3, and we expect to spend approximately $50 million on a hydrocracker project that will increase the conversion capability and the ultra-low sulfur diesel (“ULSD”) yield of the refinery. In addition, we have increased the Wynnewood refinery’s utilization rate from approximately 88% for the year ended December 31, 2011 to approximately 93% during the nine months ended

 

 

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September 30, 2012. A refinery’s utilization rate refers to average daily crude oil throughput divided by crude oil capacity (which represents the stated refining capacity of the refinery), excluding planned periods of downtime for maintenance and turnarounds.

We currently gather approximately 50,000 bpd of price-advantaged crudes from our gathering area, which includes Kansas, Nebraska, Oklahoma, Missouri and Texas. 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 allows us to supply price-advantaged Canadian and Bakken crudes to our refineries.

Since the beginning of 2011, WTI crude has priced at a considerable discount to the price of Brent crude oil (“Brent”). Other imported waterborne crude oils, and crude oil produced on-shore and off-shore in the Gulf Coast region are priced based on the price of Brent. This price advantage for the crudes that we refine is the result of increasing mid-continent domestic and Canadian crude oil production, decreasing North Sea production, economic transportation infrastructure limitations, and geopolitical factors. We expect WTI to continue to trade at a discount to Brent over the long term, but anticipate that this discount will vary over time. For example, the recent reversal of the Seaway crude oil pipeline to make it flow from Cushing to the Gulf Coast and the ongoing and planned capacity expansion of the pipeline will ameliorate some of the current transportation infrastructure limitations by increasing mid-continent producers’ ability to transport crude oil to Gulf Coast refiners in an economic manner and may reduce the robust Brent-WTI price differential. Over time, continued increases in mid-continent domestic and Canadian crude oil production, ongoing infrastructure constraints that limit the amount of crude that can be transported through the more economic pipeline network as opposed to rail or truck and continuing decline in North Sea production should continue to support wider Brent-WTI price differentials.

The following table shows average crude oil price differentials of WTI as compared to Brent, WTI to Mars Blend (“Mars”), Western Canada Select (“WCS”) to WTI, West Texas Sour (“WTS”) to WTI, and WTI priced in Midland, Texas (“WTI at Midland”) to WTI for the year ended December 31, 2011 and for the nine months ended September 30, 2012.

 

     Average Differential
($ per barrel)
 
   Year Ended
December 31, 2011
    Nine Months Ended
September 30, 2012
 

WTI—Brent(1)

   $ (16.82   $ (17.12

WTI—Mars(1)

     (12.52     (11.84

WCS—WTI(1)

     (16.70     (20.75

WTS—WTI(1)

     (2.05     (4.09

WTI at Midland—WTI(1)(2)

     (0.52     (2.87

 

(1) NYMEX WTI, WTS, Mars, WCS and Brent average prices from Bloomberg over the time periods stated above.
(2) WTI at Midland average prices from Argus Media over the time periods stated above.

Our logistics businesses have grown substantially since 2005. We have grown our crude oil gathering system from 7,000 bpd in 2005 to approximately 50,000 bpd currently. The system is supported by approximately 350 miles of owned pipelines associated with our gathering operations, over 125 crude oil transports and associated storage facilities located along our pipelines and third-party pipelines for gathering crude oil purchased from independent crude oil producers in Kansas, Nebraska, Oklahoma, Missouri and Texas. We have a 145,000 bpd pipeline system that transports crude oil from our Broome Station tank farm to our Coffeyville refinery as well as a total of 6.0 million barrels of owned and leased crude oil storage capacity, including approximately 6% of the total crude oil storage capacity at Cushing. Crude oil is transported to our

 

 

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Wynnewood refinery via two separate third-party pipelines operated by and received into storage tanks at terminals located at or near the refinery. Our crude oil gathering and pipeline systems provide us with price advantages relative to the price of WTI.

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 Midstream Partners L.P. (“Magellan”) and NuStar Energy, LP, (“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 (“pet coke”), to an affiliate, CVR Partners, LP (“CVR Partners”), pursuant to a multi-year agreement. For the year ended December 31, 2011, our two largest customers accounted for approximately 15% and 12% of our sales and approximately 64% of our sales were made to our ten largest customers.

We generated refining margin adjusted for FIFO impacts of $1,328.8 million, net income of $540.7 million and Adjusted EBITDA of $988.9 million for the nine months ended September 30, 2012. We generated refining margin adjusted for FIFO impacts of $799.6 million and $1,404.3 million, net income of $480.3 million and $618.2 million, and Adjusted EBITDA of $577.3 million and $1,013.3 million, for the year ended December 31, 2011 and twelve months ended September 30, 2012, respectively. Our results of operations include the historical results of operations of the Wynnewood refinery only for periods following our acquisition of the refinery on December 15, 2011. Pro forma for the acquisition of WEC (as defined below) and the Transactions (as defined below) we would have generated $1,225.7 million and $1,328.8 million of refining margin adjusted for FIFO impacts, $749.0 million and $565.1 million of net income and $842.7 million and $988.9 million of Adjusted EBITDA for the year ended December 31, 2011 and nine months ended September 30, 2012, respectively. For a reconciliation of refining margin adjusted for FIFO impacts and Adjusted EBITDA to the most directly comparable GAAP measures, see “—Non-GAAP Financial Measures.”

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:

Strategically Located Refineries with Advantageous Access to Crude Oil Supply. We believe that the location of our refineries and logistics assets enable us to access lower cost mid-continent domestic sweet and sour and various light and heavy grade Canadian crude oils, allowing us to improve our realized margins. For the nine months ended September 30, 2012, 12.3% of the crude oil processed at our refineries was WTS, 77.3% was domestic sweet with the remainder comprised of various light and heavy grade Canadian crude oils. Historically, we have purchased crude oil at a discount to WTI as a result of our location. From the beginning of 2007 through September 30, 2012, we realized an average discount of $3.52 per barrel of crude oil purchased for our refineries when compared to the average WTI price per barrel over the same period. More recently, the increase of the discount at which a barrel of WTI traded relative to Brent has allowed refineries, such as ours, that are capable of sourcing and utilizing crude oil that is priced by reference to WTI, to realize relatively lower crude oil costs and benefit from the refined product prices resulting from higher Brent prices.

Supporting Logistics Assets that Provide Competitive Cost Advantages. We believe that our network of pipelines, crude oil transports and storage facilities allow us to source domestically produced sweet and sour

 

 

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crudes to our refineries in a price-advantaged manner. Since 2005, our management team has grown our local gathering system from 7,000 bpd to approximately 50,000 bpd currently and it now supplies approximately one-fourth of our refineries’ crude.

Attractive Refined Products Supply/Demand Dynamics. Our refineries are located in the cost advantaged area of the PADD II region known as Group 3. Our combined production capacity represents approximately 22% of our region’s refining capacity. Since the mid-1990s, demand for refined products in the PADD II region has exceeded regional production, resulting in a need for imports from other regions, specifically from the Gulf Coast region. We benefit from the fact that the market prices in our region typically include a premium equivalent to the logistics cost for Gulf Coast suppliers to ship products into our region. Over the five-year period ended December 31, 2011, the PADD II Group 3 2-1-1 benchmark crack spread (defined as two barrels of crude producing one barrel of gasoline and one barrel of ULSD/heating oil) premium to the NYMEX 2-1-1 has been approximately $1.54 per barrel.

Substantial Refinery Operating Flexibility. Since June 2005, we have significantly expanded the variety of crude grades we are able to process at our Coffeyville refinery. Our Coffeyville refinery can now process up to 25,000 bpd of heavy sour, which was unable to be processed through our Coffeyville refinery at the time of its acquisition. Since our acquisition of the Wynnewood refinery in December 2011, we have increased the variety of crude grades that the refinery can process and plan to upgrade a hydrocracker unit at the refinery. Our proximity to, and substantial storage capacity at, the crude oil trading hub in Cushing, Oklahoma minimizes the likelihood of an interruption to our supply and facilitates optimal crude oil purchasing and blending. We maintain capacity on the Spearhead and Keystone pipelines from Canada to Cushing and also operate a crude gathering system serving Kansas, Nebraska, Oklahoma, Missouri and Texas, which allows us to acquire quality crudes at a discount to WTI. This combination of access to price-advantaged domestic and Canadian crude oils allows us to capitalize on changing market conditions and optimize our crude oil supply. In addition, our access to the mid-continent gas liquids hub of Conway, Kansas allows us to further increase our refining margins by purchasing and blending natural gasoline and butanes.

Strong Refinery Operating Track Record. Since 2005, we have invested over $700 million to modernize our Coffeyville refinery and to meet more stringent federal and state environmental, health and safety requirements. As a result of these investments, we have achieved significant increases in our Coffeyville refinery crude throughput rate from less than 90,000 barrels per stream day (“bpsd”) prior to June 2005 up to approximately 125,000 bpsd in the third quarter of 2012. In early 2012, we successfully and safely completed the second phase of our turnaround at Coffeyville at a total cost of approximately $89 million, which includes the costs of the first phase which occurred in the fourth quarter of 2011. In December 2012 we completed a major turnaround at our Wynnewood refinery, the first since we acquired this refinery in 2011, at a total cost of approximately $105 million. The next turnarounds of our Coffeyville and Wynnewood refineries are scheduled to begin in late-2015 and 2016, respectively.

Synergistic Relationship with CVR Partners. Our relationship with CVR Partners provides us with a number of operational advantages. We have the ability to purchase hydrogen from CVR Partners’ nitrogen fertilizer facility, which provides an important hydrogen supply redundancy to our Coffeyville refinery. We also share a number of utilities with CVR Partners, such as steam and water utilities, which reduces the direct operating expenses of running our Coffeyville refinery. In addition, pursuant to a long-term agreement, CVR Partners purchases 100% of the pet coke that we produce at our Coffeyville refinery, thereby assuring a guaranteed source of demand for this by-product of our refining operations.

Experienced Management Team. The operations members of our senior management team average over 35 years of refining industry experience and, in coordination with our broader management team, have increased operating income and created stockholder value since the acquisition of Coffeyville Resources in June 2005.

 

 

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Mr. John J. Lipinski, our Chief Executive Officer, has over 40 years of experience in the refining industry, and prior to joining us in connection with the acquisition of Coffeyville Resources in June 2005, was in charge of a 550,000 bpd refining system. Mr. Stanley A. Riemann, our Chief Operating Officer, has over 39 years of experience, including running one of the largest fertilizer manufacturing systems in the United States and its petroleum operations. Mr. Robert W. Haugen, our Executive Vice President, Refining Operations, has more than 30 years of experience, serving in numerous engineering, operations, marketing and management positions in the refining, petrochemical and nitrogen fertilizer industries. Mr. Wyatt E. Jernigan, our Executive Vice President, Crude Oil Acquisition and Petroleum Marketing, has more than 35 years of experience in the areas of crude oil and petroleum products as they relate to trading, marketing, logistics and asset development. Mr. Christopher G. Swanberg, our Vice President, Environmental, Health and Safety has over 32 years of experience in various positions within the petroleum refining industry. Mr. David L. Landreth, our Vice President, Economics and Planning, has more than 30 years experience in refining and petrochemicals in areas relating to crude, feedstock, product and process optimization, commercial activities, acquisitions and capital utilization.

Our Business Strategy

Our objectives are to provide attractive total returns to unitholders by focusing on business results and total distributions, optimizing our crude supply, pursuing organic growth opportunities and possible acquisitions and maintaining a conservative financial position.

Focus on Business Results and Total Distributions. We expect to focus on optimizing our business results and maximizing total distributions, rather than attempting to manage our results with a focus on minimum distributions. We do not intend to maintain excess distribution coverage in order to stabilize our quarterly distributions or to otherwise reserve cash for future distributions. The board of directors of our general partner will adopt a policy under which we will distribute all of the available cash we generate each quarter as described in “Our Cash Distribution Policy and Restrictions on Distributions.” In addition, our general partner has a non-economic interest in us and no incentive distribution rights, and, accordingly, our unitholders will receive 100% of our cash distributions.

Focus on Optimizing Our Crude Supply. Our strategic location and the complexity of each of our refineries allow us to receive and process a variety of light, heavy, sweet and sour crude oils from the United States and Canada, many of which have historically priced at a discount to WTI. Our management team continues to leverage our location, logistics infrastructure and operational flexibility to optimize our crude oil purchases and minimize our crude oil costs. In addition, we are expanding our gathering system to further increase our ability to purchase crude at a discount to WTI.

Focus on Growth Opportunities. We intend to pursue opportunities to grow our business both organically and through acquisitions.

 

   

Organic Growth Projects. We plan to continue to make investments to enhance the operating flexibility and profitability of our refineries. We intend to pursue organic growth projects at our refineries to improve the yield of transportation fuels we produce and the efficiency of our business, which we expect to improve profitability. For example, we plan to undertake process and catalyst modifications of an existing hydrocracker unit at our Wynnewood refinery, as well as to add a hydrogen plant, that will increase the conversion capability and the ULSD yield of the refinery. We also plan to make investments in our logistics operations, including trucking, storage, and pipeline facilities, to enhance our crude oil sourcing flexibility (target growth of around 10% per year) and to reduce related crude oil purchasing and delivery costs.

 

   

Evaluate Accretive Acquisition Opportunities. We will selectively pursue accretive acquisitions. In evaluating acquisitions, we will consider, among other factors, sustainable performance of the targeted assets through the refining cycle, access to advantageous sources of crude oil supplies, attractive supply

 

 

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and demand market fundamentals, access to distribution and logistics infrastructure and potential operating synergies.

Maintain a Conservative Financial Position. We intend to maintain a conservative total debt level. We plan to retain significant financial flexibility during periods of volatile commodity prices by maintaining a number of sources of liquidity, including cash on hand, our $400 million asset-backed revolving credit facility, our $150 million senior unsecured revolving credit facility with Coffeyville Resources. We intend to prudently finance our growth capital expenditures on a long term basis with a mix of debt and equity to continue to maintain a conservative total debt level. We may fund expansion capital expenditures, on an interim basis, with our $150 million intercompany credit facility, and thereafter issue term indebtedness and equity securities to finance such growth capital expenditures on a long term basis. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources.” Additionally, we manage our operations prudently with a focus on maintaining sufficient liquidity to meet unforeseen capital needs. At the closing of this offering, after giving effect to the Transactions (as defined below) we expect to have approximately $862.8 million of available liquidity, comprised of $340.0 million of cash on hand, $372.8 million available for borrowing under our $400 million asset-backed revolving credit facility (net of $27.2 million of outstanding letters of credit) and $150.0 million available for borrowing under our $150 million senior unsecured revolving credit facility with Coffeyville Resources. In addition, we have financial flexibility resulting from trade credit from our crude oil suppliers and our Crude Oil Supply Agreement (the “Vitol Agreement”) with Vitol Inc. (“Vitol”), which helps reduce the amount of working capital required in our refinery operations. For the year ended December 31, 2011 and for the nine months ended September 30, 2012 we obtained approximately 65% and 63%, respectively, of the crude oil for our Coffeyville refinery under the Vitol Agreement, which was amended and restated in August 2012 to include the provision of crude oil intermediation services for our Wynnewood refinery and to extend the initial term of the agreement.

Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel, asphalt and other products. Refining is primarily a margin-based business where the crude oil and other feedstocks and refined products are commodities with fluctuating prices. In order to increase profitability, it is important for a refinery to maximize the yields of high value finished products and to minimize the costs of feedstocks and operating expenses, and to do so without compromising safety and environmental performance.

According to the Energy Information Administration (the “EIA”), as of January 1, 2012, there were 134 oil refineries operating in the United States. High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. Domestic operating refining capacity has increased approximately 4% between January 1982 and January 2012, from 16.1 million bpd to 16.7 million bpd, according to the EIA. Much of this increase in capacity is generally the result of efficiency measures and moderate expansions at various refineries, known as “capacity creep,” but some significant expansions at existing refineries have occurred as well. During this same time period, more than 120 generally smaller and less efficient refineries were closed.

According to the EIA, total demand for refined products in Group 3 of the PADD II region, where we operate, was over 330 million barrels in 2011. The refining capacity in this region is currently insufficient to meet the demand for refined products. Refining capacity in Group 3 decreased approximately 22% between January 1982 and January 2012, from approximately 1.1 million bpd to approximately 850,000 bpd. The refined product volumes that are necessary to satisfy the demand in excess of Group 3 production are primarily sourced from domestic refineries located outside of the PADD II region, particularly from the Gulf Coast. According to the EIA, due to product supply shortfalls within Group 3, net receipts of gasoline and distillate from domestic sources outside of Group 3 comprised approximately 13% and 14%, respectively, of demand for these products on average over the 2007—2011 period.

 

 

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The volume of crude oil moving by pipeline from PADD III to PADD II has steadily declined in recent years, as pipeline receipts of Canadian oil sands crude oil and production from domestic oil plays continue to increase. According to the EIA, Canadian crude oil imports into the PADD II region averaged 1.7 million bpd in August 2012, up 41% over August 2010 volumes. The PADD II Group 3 refiners also have access to the growing crude oil supply forecasted to come from North Dakota’s Bakken shale, as well as from the Permian Basin, Anadarko Basin, DJ Basin and other regional liquids plays. According to ITG Investment Research, an independent research firm, liquids production from the Permian, Bakken, Anadarko Basin (which includes the Mississippi Lime, Granite Wash and Cleveland Tonkawa, among others) and DJ Basin (primarily the Niobrara) is expected to double from approximately 2.5 million bpd at the end of 2011 to more than 4.0 million bpd by the end of 2015 and increase to approximately 5.5 million bpd by 2024.

Conflicts of Interest and Fiduciary Duties

Our general partner has a legal duty to manage us in good faith. However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its indirect owner, CVR Energy. As a result, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and CVR Energy, on the other hand. Our partnership agreement limits the liability and reduces the duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of our general partner’s duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and the duties of our general partner, see “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, see “Certain Relationships and Related Party Transactions.”

Our Relationship with CVR Energy and Icahn Enterprises, L.P.

Following this offering, CVR Refining Holdings, LLC, an indirect wholly-owned subsidiary of CVR Energy, will own 100% of our general partner and approximately 86.4% of our common units.

CVR Energy (NYSE: CVI) is a publicly traded Delaware corporation which indirectly owns the general partner and approximately 70% of the common units of CVR Partners (NYSE: UAN), a publicly-traded limited partnership that is an independent producer and marketer of upgraded nitrogen fertilizers in the form of ammonia and urea ammonium nitrate (“UAN”). Icahn Enterprises, L.P. (“Icahn Enterprises”) (NASDAQ: IEP), a master limited partnership which holds interests in operating subsidiaries engaged in various industries, is the holder of 82% of the common stock of CVR Energy. Icahn Enterprises has indicated that it or its affiliates may purchase in this offering up to $100.0 million, or up to approximately 4,000,000 (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common units at the same price as the price to the public, in which case they would directly own, upon completion of the offering, approximately 2.7% of our common units.

About Us

CVR Refining, LP was formed in Delaware in September 2012. Our principal executive offices are located at 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479, and our telephone number is (281) 207-3200. Upon completion of this offering, our website address will be www.cvrrefining.com. Information contained on our website or CVR Energy’s website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.

 

 

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Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. These risks are described under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” You should carefully consider these risk factors together with all other information included in this prospectus.

Recent Developments

Preliminary Operating Data for the Three Months Ended December 31, 2012

We have not yet finalized our financial statement close process for the quarter ended December 31, 2012 and our independent auditors have not yet completed their year-end audit. In connection with the completion of these activities, we may identify items that would require us to make adjustments to our preliminary operating results set forth below. Important factors that could cause actual results to differ materially from our preliminary estimates are set forth under the headings “Risk Factors” and “Forward-Looking Statements.” Our combined financial statements as of and for the year ended December 31, 2012 will not be available until after this offering is completed, and consequently, will not be available to you prior to investing in this offering.

Based on our preliminary operating results for the three months ending December 31, 2012, we expect to report total crude oil throughput for the three months ended December 31, 2012 of approximately 147,000 bpd comprised of approximately 124,000 bpd for the Coffeyville refinery and approximately 23,000 bpd for the Wynnewood refinery. This compares to total crude oil throughput of 93,705 bpd for the three months ended December 31, 2011. The increase is attributable to both the inclusion of Wynnewood’s operating results for a greater portion of the three months ended December 31, 2012 than the corresponding period of 2011, since we acquired the Wynnewood refinery on December 16, 2011, and the impacts of the turnaround of the Coffeyville refinery in the fourth quarter of 2011.

Completion of Wynnewood Turnaround

In December 2012, we completed the scheduled turnaround at our Wynnewood refinery, the first since our acquisition of the refinery in December 2011, at a total cost of approximately $105.0 million. The downtime associated with this turnaround significantly impacted our results of operations for the fourth quarter of 2012.

Amended and Restated Asset-Backed Revolving Credit Facility

On December 20, 2012, we entered into an amended and restated asset-backed revolving credit agreement (the “New ABL Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and collateral agent for a syndicate of lenders. Under the New ABL Credit Facility, we will assume Coffeyville Resources’ position as borrower and its obligations under the New ABL Credit Facility upon the closing of this offering. The New ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swing line loans of $360.0 million and $40.0 million, respectively. The New ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities—New ABL Credit Facility” for a further discussion of the terms of the New ABL Credit Facility.

The Transactions

In connection with this offering, the following transactions have occurred or will occur:

 

   

Coffeyville Resources has formed CVR Refining Holdings;

 

 

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CVR Refining Holdings has formed CVR Refining GP;

 

   

CVR Refining Holdings and CVR Refining GP have formed CVR Refining, LP, and CVR Refining, LP has issued to them a 100% limited partner interest and a non-economic general partner interest, respectively;

 

   

CVR Refining Holdings has formed CVR Refining, LLC, and Coffeyville Resources has contributed all of its petroleum refining and logistics operating subsidiaries, as well as its equity interests in Coffeyville Finance Inc., to CVR Refining, LLC;

 

   

On October 23, 2012, CVR Refining, LLC and Coffeyville Finance issued $500 million aggregate principal amount of 6.5% senior notes due 2022, which we refer to as the “New Notes.” The New Notes were sold in an offering exempt from registration under the Securities Act of 1933, as amended, or the Securities Act, to qualified institutional investors in reliance on Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act. CVR Refining, LLC and Coffeyville Finance received net proceeds of approximately $492.5 million from the offering, after deducting initial purchasers’ commissions. CVR Refining, LLC and Coffeyville Finance used the net proceeds from the offering to finance the purchase and redemption of the 9.0% first lien senior secured notes due 2015 issued by Coffeyville Resources, which we refer to as the “First Lien Notes,” and for general corporate purposes;

 

   

On December 31, 2012, CVR Refining Holdings contributed its 100% membership interest in CVR Refining, LLC to us and Coffeyville Resources, on behalf of CVR Refining Holdings, will, if necessary, contribute to us an amount of cash such that we will have approximately $340 million of cash on hand at the closing of this offering. If such amount of cash on hand at the closing of this offering exceeds $340 million, we will distribute the excess to Coffeyville Resources.

 

   

On December 20, 2012, we entered into the New ABL Credit Facility that amended and restated Coffeyville Resources’ existing asset-based revolving credit facility (the “ABL credit facility”), and under which we will become the borrowers and assume the obligations of Coffeyville Resources upon the consummation of this offering;

 

   

Prior to the closing of this offering, we will enter into a new $150 million senior unsecured revolving credit facility with Coffeyville Resources as the lender (the “intercompany credit facility”);

 

   

On the closing date of this offering, we will enter into a Services Agreement, pursuant to which we and our general partner will obtain certain management and other services from CVR Energy;

 

   

On the closing date of this offering, we will issue and sell 20,000,000 common units (including to Icahn Enterprises or its affiliates) in this offering and pay related underwriting discounts and commissions, structuring fees and all related unpaid transaction costs in connection with this offering; and

 

   

We will use the net proceeds from the sale of 20,000,000 common units in this offering in the manner described under “Use of Proceeds.”

We have granted the underwriters a 30-day option to purchase up to an aggregate of 3,000,000 additional common units. Any net proceeds received from the exercise of this option will be distributed to CVR Refining Holdings. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to CVR Refining Holdings at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

We refer to the above transactions throughout this prospectus as the “Transactions.”

 

 

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Organizational Structure

The following chart illustrates our organizational structure and the organizational structure of CVR Energy after giving effect to the Transactions (assuming the underwriter’s option to purchase additional common units is not exercised, and assuming Icahn Enterprises purchases 4,000,000 common units in this offering):

 

LOGO

 

 

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THE OFFERING

 

Issuer

CVR Refining, LP

 

Common units offered

20,000,000 common units.

 

Option to purchase additional common units

We have granted the underwriters a 30-day option to purchase up to an additional 3,000,000 common units.

 

Units outstanding after this offering

147,600,000 common units.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $469.0 million from this offering (based on an assumed initial offering price of $25.00 per common unit), after deducting the estimated underwriting discounts and commissions, offering expenses, and structuring fees payable by us in the following manner:

 

   

$255.0 million to repurchase the 10.875% of senior secured notes due 2017 issued by Coffeyville Resources and pay associated accrued interest;

 

   

$160.0 million to prefund certain maintenance and environmental capital expenditures through 2014; and

 

   

$54.0 million to fund the turnaround expenses of our Wynnewood refinery in the fourth quarter of 2012.

 

  The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $70.9 million based on an assumed initial offering price of $25.00 per common unit, if exercised in full) will be used to pay a distribution to CVR Refining Holdings. If Icahn or its affiliates purchase $100.0 million of common units in this offering, then our net proceeds will increase by approximately $5.5 million. Please read “Use of Proceeds.”

 

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2013, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will consist of available cash (as described below) for the period from the closing of this offering through March 31, 2013.

 

  The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the available cash we generate in such quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service, maintenance and environmental capital expenditures, and reserves for expenses associated with our major scheduled turnarounds. The board of directors may also determine that it is appropriate to reserve cash for future operating or capital needs.

 

 

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  We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not 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 an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our earnings during each quarter. As a result, our quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) our operating performance, (ii) earnings caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices we receive for finished products, changes to working capital or capital expenditures and (iii) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

 

  Based upon our forecast for the twelve months ending December 31, 2013, and assuming the board of directors of our general partner declares distributions in accordance with our cash distribution policy, we expect that our aggregate distributions for the twelve months ending December 31, 2013 will be approximately $696.9 million, or $4.7215 per common unit. See “Our Cash Distribution Policy and Restrictions on Distributions—Forecasted Available Cash.” Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, earnings, need for reserves and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations, earnings and financial condition. In addition, the board of directors of our general partner may be required to, or may elect to, eliminate our distributions during periods of high prices for crude oil or other feedstocks, or during periods of reduced prices or demand for our refined products, among other reasons. Please see “Risk Factors.”

 

 

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  For a calculation of our ability to make distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2011 and the twelve months ended September 30, 2012, see “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Combined Available Cash.” Our pro forma available cash generated during the year ended December 31, 2011 and twelve months ended September 30, 2012, would have been $638.8 million (or $4.33 per common unit) and $844.2 million (or $5.72 per common unit), respectively.

 

Subordinated units

None.

 

Incentive Distribution Rights

None.

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the unitholders holding at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. As the owner of CVR Refining Holdings, CVR Energy will own an aggregate of 86.4% of our common units (or 84.4% of our common units, if the underwriters exercise their option to purchase additional common units in full) upon the consummation of this offering. This will effectively give CVR Energy the ability to prevent the removal of our general partner. In addition, if Icahn Enterprises or its affiliates purchase $100.0 million, or 4,000,000 (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common units in this offering, they will directly own approximately 2.7% of our common units. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates (including CVR Energy and Icahn Enterprises) own more than 95% of the units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the units held by unaffiliated unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. See “The Partnership Agreement—Call Right.”

 

 

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Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2014, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 50% of the cash distributed to you. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

 

Exchange listing

Our common units have been approved for listing on the New York Stock Exchange (the “NYSE”) under the symbol “CVRR.”

 

 

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SUMMARY HISTORICAL AND UNAUDITED PRO FORMA COMBINED FINANCIAL AND OPERATING DATA

The Partnership was formed in September 2012 and does not have historical financial statements. Therefore, in this prospectus we present the historical combined financial and operating results of the petroleum refining and related logistics business of CVR Energy. Coffeyville Resources, an indirect wholly-owned subsidiary of CVR Energy, has formed CVR Refining Holdings, which has formed CVR Refining, LLC. On October 18, 2012, Coffeyville Resources contributed all of its interests in the operating subsidiaries which constitute its petroleum refining and logistics business, as well as Coffeyville Finance Inc., to CVR Refining, LLC. On December 31, 2012, CVR Refining Holdings contributed its 100% membership interest in CVR Refining, LLC to us. Coffeyville Resources has retained its other assets, including an approximate 70% limited partner interest in CVR Partners, LP and a 100% membership interest in CVR GP, LLC, the general partner of CVR Partners. The following table also presents summary unaudited pro forma combined financial and operating data of CVR Refining, LP as of the dates and for the periods indicated.

The summary historical combined financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2009, 2010 and 2011 and the summary historical combined financial information presented below under the caption Balance Sheet Data as of December 31, 2010 and 2011, have been derived from CVR Refining, LP’s audited combined financial statements included elsewhere in this prospectus, which financial statements have been audited by KPMG LLP, an independent registered public accounting firm. The summary combined financial information presented below under the caption Statement of Operations Data for the nine months ended September 30, 2011 and 2012 and the summary combined financial data presented below under the caption Balance Sheet Data as of September 30, 2012 are derived from our unaudited combined financial statements included in this prospectus which, in the opinion of management, include all adjustments, consisting of only normal, recurring adjustments, necessary for the fair presentation of the results for the unaudited interim periods.

On December 15, 2011, Coffeyville Resources acquired all of the issued and outstanding shares of Gary-Williams Energy Corporation (subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC). Wynnewood Energy Company, LLC owns Wynnewood Refining Company, LLC, which owns and operates the refinery in Wynnewood, Oklahoma. We refer to Wynnewood Energy Company, LLC and its subsidiaries as “WEC.” WEC’s audited consolidated financial statements and related notes as of and for the years ended December 31, 2009 and 2010 are included elsewhere in this prospectus.

The summary pro forma combined financial data presented for the year ended December 31, 2011 and the nine months ended September 30, 2012 is derived from our unaudited pro forma combined financial statements included elsewhere in this prospectus. Our unaudited pro forma combined financial statements give pro forma effect, where applicable, to the following:

 

   

the acquisition of WEC; and

 

   

the Transactions described under “—The Transactions.”

The unaudited pro forma combined balance sheet as of September 30, 2012 assumes the events listed above occurred as of September 30, 2012. The unaudited pro forma combined statement of operations data for the year ended December 31, 2011 and the nine months ended September 30, 2012 assume the events listed above occurred as of January 1, 2011.

The historical combined financial data presented below has been derived from combined financial statements that have been prepared using accounting principles generally accepted in the United States (“GAAP”), and the unaudited pro forma combined financial data presented below has been derived from the

 

 

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“Unaudited Pro Forma Combined Financial Statements” included elsewhere in this prospectus. This data should be read in conjunction with, and is qualified in its entirety by reference to, the combined financial statements and related notes included elsewhere in this prospectus.

We have not given pro forma effect to incremental general and administrative expenses of approximately $5.0 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer insurance expenses; and director and officer compensation expenses.

Pro forma net income per unit is determined by dividing pro forma net income by the number of common units expected to be outstanding at the closing of this offering. All units were assumed to have been outstanding since January 1, 2011. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of this offering.

For a detailed discussion of the summary historical combined financial information and operating data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited and unaudited historical combined financial statements of CVR Refining, LP and our unaudited pro forma combined financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
              

Year Ended
December 31,

2011

   

Nine Months
Ended
September 30,

2012(1)

 
    Year Ended December 31,     Nine Months Ended
September 30,
          
    2009     2010     2011(1)     2011     2012(1)           
                      (unaudited)          (unaudited)  
    (in millions, except per unit data and as otherwise indicated)  

Statement of Operations Data:

                 

Net sales

  $ 2,936.5      $ 3,905.6      $ 4,752.8      $ 3,773.3      $ 6,465.5          $ 7,398.3      $ 6,465.5   

Costs and expenses:

                 

Cost of product sold(2)

    2,515.9        3,539.8        3,927.6        3,078.5        5,191.0            6,126.0        5,191.0   

Direct operating expenses(2)

    142.2        153.1        247.7        144.0        253.1            345.0        253.1   

Selling, general and administrative expenses(2)

    40.0        43.1        51.0        31.4        67.5            72.7        67.5   

Depreciation and amortization

    64.4        66.4        69.8        50.9        80.4            98.9        80.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Operating income

  $ 174.0      $ 103.2      $ 456.7      $ 468.5      $ 873.5          $ 755.7      $ 873.5   

Other income (expense), net(3)

    (0.3     (13.8     (1.5     (1.2     0.6            (1.4     0.6   

Interest expense and other financing costs

    (43.8     (49.7     (53.0     (39.2     (56.0         (41.7     (31.6

Realized gain (loss) on derivatives, net

    (27.5     (2.1     (7.2     (18.3     (80.4         (49.0     (80.4

Unrealized gain (loss) on derivatives, net

    (37.8     0.6        85.3        (6.8     (197.0         85.4        (197.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Net income(3)

  $ 64.6      $ 38.2      $ 480.3      $ 402.8      $ 540.7          $ 749.0      $ 565.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Pro forma net income per common unit, basic and diluted

                $ 5.07      $ 3.83   

Pro forma number common units outstanding, basic and diluted

                  147.6        147.6   
 

Balance Sheet Data (at period end):

   

 

(unaudited)

 

  

 

             

Cash and cash equivalents(4)

  $ 2.7      $ 2.3      $ 2.7      $ —        $ 79.5          $ 340.0      $ 340.0   

Working capital

    173.7        138.7        384.7        160.5        336.4            734.9        625.7   

Total assets

    1,104.4        1,072.8        2,262.4        1,154.4        2,212.7            2,593.7        2,469.8   

Total debt, including current portion

    479.5        469.0        729.9        466.7        727.0            553.2        552.5   

Total divisional equity/partners’ capital

    485.4        418.8        1,018.6        444.5        937.7            1,542.6        1,401.5   
 

Cash Flow Data

                 

Net cash flow provided by (used in):

                 

Operating activities

  $ 31.9      $ 167.0      $ 352.7      $ 424.9      $ 799.2           

Investing activities

    (33.6     (21.1     (655.9     (33.5     (82.4        

Financing activities(4)

    3.8        (146.3     303.6        (393.7     (640.0        

 

 

16


Table of Contents
Index to Financial Statements
    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
              

Year Ended
December 31,

2011

   

Nine Months
Ended
September 30,

2012(1)

 
    Year Ended December 31,     Nine Months Ended
September 30,
          
    2009     2010     2011(1)     2011     2012(1)           
                      (unaudited)          (unaudited)  
    (in millions, except per unit data and as otherwise indicated)  
 

Other Financial Data

                 

Capital expenditures for property, plant and equipment

  $ 34.0      $ 21.2      $ 68.8      $ 33.6      $ 82.8          $ 87.6      $ 82.8   

Adjusted EBITDA(5)

  $ 147.3      $ 152.6      $ 577.3      $ 525.0      $ 988.9          $ 842.7      $ 988.9   
 

Key Operating Data(1)

                 

Crude oil throughput (bpd)(6):

                 

Sweet

    82,598        89,746        83,538        85,401        136,463            132,638        136,463   

Medium

    15,602        8,180        1,704        598        21,708            11,338        21,708   

Heavy sour

    10,026        15,439        18,460        21,071        18,418            18,460        18,418   

All other feedstocks and blendstocks

    12,013        10,350        5,231        5,671        9,448            8,466        9,448   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total throughput (bpd)(6)

    120,239        123,715        108,933        112,741        186,037            170,902        186,037   

Production (bpd)(6):

                 

Gasoline

    62,309        61,136        48,486        50,998        92,114            80,704        92,114   

Distillate

    46,909        50,439        45,535        47,368        75,568            65,321        75,568   

Other

    11,549        12,978        15,385        15,038        17,588            22,895        17,588   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total refining production (excluding internally produced fuel)

    120,767        124,553        109,406        113,404        185,270            168,920        185,270   

Utilization(7)

    94.1     98.6     87.8     95.5     93.1         92.4     93.1

NYMEX 2-1-1 crack spread (per barrel)(8)

    8.54        10.07        26.33        27.27        29.87            26.33        29.87   

Product prices (per barrel)(9)

  $ 74.67      $ 93.01      $ 125.86        $ 125.76            $ 125.76   

PADD II Group 3 2-1-1 crack spread (per barrel)(8)

  $ 7.93      $ 10.01      $ 26.77      $ 27.82      $ 29.60            26.77        29.60   

Refining margin per crude oil throughput barrel(5)

  $ 10.65      $ 8.84      $ 21.80      $ 23.77      $ 26.34          $ 21.46      $ 26.34   

Refining margin per crude oil throughput barrel adjusted for FIFO impact(5)

    8.93        8.07        21.12        23.82        27.46            20.67        27.46   

Direct operating expenses (excluding major scheduled turnaround expenses) per crude oil throughput barrel(2)(5)

  $ 3.60      $ 3.67      $ 4.79      $ 4.51      $ 4.52            4.70        4.52   

Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact) per crude oil throughput barrel(5)

  $ 3.70      $ 2.80      $ 14.49      $ 17.57      $ 21.29          $ 14.31      $ 21.29   

 

(1) We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition. In addition, we incurred approximately $5.2 million of transaction and integration costs related to the acquisition in fiscal year 2011 and approximately $10.3 million for the nine months ended September 30, 2012. These transactions impact the comparability of the Summary Historical and Unaudited Pro Forma Combined Financial and Operating Data. Key operating data includes WEC numbers for the period beginning December 16, 2011 through September 30, 2012.
(2) Amounts are shown exclusive of depreciation and amortization.
(3) The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature and are not otherwise presented above:

 

 

17


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Index to Financial Statements
    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
             

Year Ended

December 31,

2011

   

Nine Months Ended
September 30,

2012

 
    Year Ended December 31,     Nine Months  Ended
September 30,
          
        2009             2010             2011             2011             2012               
                      (unaudited)          (unaudited)  
    (in millions)  

Loss on extinguishment of debt(a)

  $ 2.1      $ 16.6      $ 2.1      $ 2.1      $ —            $ 2.1      $ —     

Loss on disposition of assets

    —          1.3        2.5        1.5        —              2.5        —     

Letter of credit expense and interest rate swap not included in interest expense(b)

    13.4        4.7        1.5        1.3        0.9            1.5        0.9   

Wynnewood acquisition transaction fees and integration expense

    —          —          5.2        —          10.3            5.2        10.3   

Major scheduled turnaround expense(c)

    —          1.2        66.4        12.2        34.6            66.4        34.6   

Share-based compensation(d)

    2.5        11.5        8.9        8.0        15.6            8.9        15.6   

 

  (a) For the nine months ended September 30, 2011 and the year ended December 31, 2011, the write-off of a portion of previously deferred financing costs upon the replacement of a previous credit facility (the “first priority credit facility”) with the ABL credit facility contributed to $1.9 million of the loss on extinguishment of debt. Additionally, $0.2 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs and unamortized original issue discount associated with the repurchase of $2.7 million of First Lien Notes. For the year ended December 31, 2010, a premium of 2.0% paid in connection with unscheduled prepayments and payoff of our tranche D term loan contributed $9.6 million of the loss on extinguishment of debt. Additionally, $5.4 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs associated with the payoff of the tranche D term loan. Concurrent with the issuance of the senior secured notes, $0.1 million of third-party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our senior secured notes resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling $1.6 million. For the year ended December 31, 2009, the $2.1 million represents the write-off of previously deferred financing costs in connection with the reduction, effective June 1, 2009, and eventual termination of the first priority funded letter of credit facility on October 15, 2009.
  (b) Consists of fees which are expensed to selling, general and administrative expenses in connection with our letters of credit outstanding and the first priority funded letter of credit facility issued in support of our cash flow swap, until it was terminated effective October 15, 2009.
  (c) Represents expense associated with major scheduled turnarounds at the refineries.
  (d) Represents the impact of share-based compensation awards.

 

(4) Coffeyville Resources has historically provided cash as necessary to support our operations and has retained excess cash generated by our operations. Cash received, or paid by, Coffeyville Resources on our behalf has been recorded as net contributions from, or net distributions to, parent, respectively, as a component of divisional equity in our combined financial statements, and as a financing activity in our Combined Statement of Cash Flows. Net contributions from/(distributions to) parent included in cash flows from financing activities were $(385.1) million and $(637.2) million for the nine months ended September 30, 2011 and 2012, respectively, and $12.6 million, $(116.3) million and $110.6 million for the years ended December 31, 2009, 2010 and 2011, respectively.
(5) For a reconciliation to the most directly comparable GAAP financial measures, please see “—Non-GAAP Financial Measures” below.
(6) Barrels per day is calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facilities’ continuous operations.
(7) Utilization refers to the average daily crude oil throughput divided by crude oil capacity (which represents the stated refining capacity of the refinery), excluding planned periods of downtime for maintenance and turnarounds. The capacity used to calculate our utilization was 115,000, 115,000 and 118,068 for the years ended December 31, 2009, 2010 and 2011, respectively, and 115,000 and 185,000, for the nine months ended September 30, 2011 and 2012, respectively.
(8) Data published by Platts and Oil Price Information Service and represents average pricing for the periods presented.

 

 

18


Table of Contents
Index to Financial Statements
(9) The product prices are calculated as the average price of WTI plus the implied 2-1-1 crack spread for our products, calculated as the NYMEX 2-1-1 crack spread per barrel adjusted for our historical product basis differential and the average discount to the price of WTI of the crude we purchased for each of the periods presented. The implied 2-1-1 crack spread indicated below is not a full representation of the realized refining gross margin as it does not include asphalt and other lower margin products. The product prices for each of the periods presented are calculated as follows:

 

    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
             

Nine Months Ended
September 30,

2012

 
    Year Ended December 31,     Nine Months Ended
September 30,

    2012    
        
        2009             2010             2011               
                      (unaudited)          (unaudited)  
    (in millions)  

Average WTI price (per barrel)

  $ 62.09      $ 79.61      $ 95.11      $ 96.16          $ 96.16   

NYMEX 2-1-1 crack spread (per barrel)

    8.54        10.07        26.33        29.87            29.87   

Product basis (per barrel)

    (0.61     (0.06     0.44        (0.27         (0.27

Crude discount (per barrel)

    4.65        3.39        3.98        —              —     
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

 

Implied 2-1-1 crack spread (per barrel)

    12.58        13.40        30.75        29.60            29.60   
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

 

Product prices (per barrel)

  $ 74.67      $ 93.01      $ 125.86      $ 125.76          $ 125.76   
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

 

 

 

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Index to Financial Statements

Non-GAAP Financial Measures

Refining Margin Per Crude Oil Throughput Barrel. Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) divided by our refineries’ crude oil throughput volumes for the respective periods presented. Refining margin per crude oil throughput barrel is a non-GAAP measure that should not be substituted for gross profit or operating income. Management believes this measure is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Our calculation of refining margin per crude oil throughput barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. We use refining margin per crude oil throughput barrel as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability. A reconciliation of net sales to refining margin per crude oil throughput barrel for the periods presented is included below.

Refining Margin Per Crude Oil Throughput Barrel Adjusted for FIFO Impact. Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) adjusted for FIFO impacts divided by our refineries’ crude oil throughput volumes for the respective periods presented. Refining margin adjusted for FIFO impact is a non-GAAP measure that we believe is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of product sold (taking into account the impact of our utilization of FIFO) that we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. A reconciliation of net sales to refining margin per crude oil throughput barrel adjusted for FIFO impact is included below:

 

    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
      Year Ended
December 31,

2011
    Nine Months Ended
September 30,

2012
 
  Year Ended December 31,     Nine Months Ended
September 30,
       
  2009     2010     2011     2011     2012        
                      (unaudited)          (unaudited)  
    (in millions)            

Net sales

  $ 2,936.5      $ 3,905.6      $ 4,752.8      $ 3,773.3      $ 6,465.5          $ 7,398.3      $ 6,465.5   

Less: cost of product sold (exclusive of depreciation and amortization)

    2,515.9        3,539.8        3,927.6        3,078.5        5,191.0            6,126.0        5,191.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Refining margin

    420.6        365.8        825.2        694.8        1,274.5            1,272.3        1,274.5   

FIFO impacts (favorable), unfavorable

    (67.9     (31.7     (25.6     1.5        54.3            (46.6     54.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Refining margin adjusted for FIFO impact

    352.7        334.1        799.6        696.3        1,328.8            1,225.7        1,328.8   

Crude oil throughput(bpd)

    108,226        113,365        103,702        107,070        176,589            162,437        176,589   

Refining margin per crude oil throughput barrel

  $ 10.65      $ 8.84      $ 21.80      $ 23.77      $ 26.34          $ 21.46      $ 26.34   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Refining margin per crude oil throughput barrel adjusted for FIFO impact

  $ 8.93      $ 8.07      $ 21.12      $ 23.82      $ 27.46          $ 20.67      $ 27.46   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

 

 

20


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Index to Financial Statements

EBITDA. EBITDA is defined as net income before income tax expense, net interest (income) expense and depreciation and amortization expense. EBITDA is not a recognized term under GAAP and should not be substituted for net income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that EBITDA provides relevant and useful information that enables external users of our financial statements, such as industry analysts, investors, lenders and rating agencies to better understand and evaluate our ongoing operating results and allows for greater transparency in the review of our overall financial, operational and economic performance.

Adjusted EBITDA. Adjusted EBITDA represents EBITDA adjusted for FIFO impacts (favorable) unfavorable (as described below), share-based compensation, and where applicable, loss on extinguishment of debt, major scheduled turnaround expenses, Wynnewood acquisition transaction fees and integration expense, loss on disposition of assets and unrealized gain (loss) on derivatives, net. Adjusted EBITDA is a supplemental measure of our performance that is not required by, nor presented in accordance with, GAAP. Management believes that Adjusted EBITDA provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of net income to EBITDA, and EBITDA to Adjusted EBITDA for the periods presented:

 

     CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
     Year Ended December 31,     Nine Months Ended
September 30,
          Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012           2011     2012  
                       (unaudited)           (unaudited)  
   (in millions)  

Net income

   $ 64.6      $ 38.2      $ 480.3      $ 402.8      $ 540.7           $ 749.0      $ 565.1   

Add:

                   

Interest expense and other financing costs

     43.8        49.7        53.0        39.2        56.0             41.7        31.6   

Depreciation and amortization

     64.4        66.4        69.8        50.9        80.4             98.9        80.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

        

 

 

   

 

 

 

EBITDA

   $ 172.8      $ 154.3      $ 603.1      $ 492.9      $ 677.1           $ 889.6      $ 677.1   

Add:

                   

FIFO impacts (favorable), unfavorable(a)

     (67.9     (31.7     (25.6     1.5        54.3             (46.6     54.3   

Share-based compensation

     2.5        11.5        8.9        8.0        15.6             8.9        15.6   

Loss on disposition of assets

     —          1.3        2.5        1.5        —               2.5        —     

Loss on extinguishment of debt

     2.1        16.6        2.1        2.1        —               2.1        —     

Wynnewood acquisition transaction fees and integration expenses

     —          —          5.2        —          10.3             5.2        10.3   

Major scheduled turnaround expenses

     —          1.2        66.4        12.2        34.6             66.4        34.6   

Unrealized (gain) loss on derivatives, net

     37.8        (0.6     (85.3     6.8        197.0             (85.4     197.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

        

 

 

   

 

 

 

Adjusted EBITDA

   $ 147.3      $ 152.6      $ 577.3      $ 525.0      $ 988.9           $ 842.7      $ 988.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

        

 

 

   

 

 

 

 

 

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(a) FIFO is our basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.

Direct Operating Expenses (Excluding Major Scheduled Turnaround Expenses) Per Crude Oil Throughput Barrel. Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel is a measurement calculated by excluding major scheduled turnaround expenses from direct operating expenses (exclusive of depreciation and amortization) divided by our refineries’ crude oil throughput volumes for the respective periods presented. Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel is a supplemental measure of our performance that is not required by, nor presented in accordance with, GAAP. Management believes direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput most directly represents ongoing direct operating expenses at our refineries. Below is a reconciliation of direct operating expenses to direct operating expenses excluding major scheduled turnaround expense for the periods presented:

 

    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
    Year Ended December 31,     Nine Months Ended
September 30,
         Year Ended
December 31,
    Nine Months Ended
September 30,
 
    2009     2010     2011     2011     2012          2011     2012  
                            (unaudited)          (unaudited)  
  (in millions)  

Direct operating expenses

  $ 142.2      $ 153.1      $ 247.7      $ 144.0      $ 253.1          $ 345.0      $ 253.1   

Less: Major scheduled turnaround expense

    —          (1.2     (66.4     (12.2     (34.6         (66.4     (34.6
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Direct operating expenses excluding major scheduled turnaround expenses

    142.2        151.9        181.3        131.8        218.5            278.6        218.5   

Crude oil throughput(bpd)

    108,226        113,365        103,702        107,070        176,589            162,437        176,589   

Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel

  $ 3.60      $ 3.67      $ 4.79      $ 4.51      $ 4.52          $ 4.70      $ 4.52   

 

 

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Gross Profit (Excluding Major Scheduled Turnaround Expenses and Adjusted for FIFO Impacts) Per Crude Oil Throughput Barrel. Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts per crude oil throughput barrel is calculated as the difference between net sales, cost of product sold (exclusive of depreciation and amortization) adjusted for FIFO impacts, direct operating expenses (exclusive of depreciation and amortization) excluding scheduled turnaround expenses divided by our refineries’ crude oil throughput volumes for the respective periods presented. Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts is a non-GAAP measure that should not be substituted for gross profit or operating income. Management believes it is important to investors in evaluating our refineries’ performance and our ongoing operating results. Our calculation of gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts per crude oil throughput may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. A reconciliation of net sales to gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts for the periods presented is included below:

 

    CVR Refining, LP Historical Combined          CVR Refining, LP
Combined Pro Forma
 
    Year Ended December 31,     Nine Months Ended
September 30,
         Year Ended
December 31,
    Nine Months Ended
September 30,
 
    2009     2010     2011     2011     2012          2011     2012  
                            (unaudited)          (unaudited)  
  (in millions)  

Net sales

  $ 2,936.5      $ 3,905.6      $ 4,752.8      $ 3,773.3      $ 6,465.5          $ 7,398.3      $ 6,465.5   

Cost of product sold

    2,515.9        3,539.8        3,927.6        3,078.5        5,191.0            6,126.0        5,191.0   

Direct operating expenses

  $ 142.2      $ 153.1      $ 247.7      $ 144.0      $ 253.1            345.0        253.1   

Depreciation and amortization

    64.4        66.4        69.8        50.9        80.4            98.9        80.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Gross profit

    214.0        146.3        507.7        499.9        941.0          $ 828.4      $ 941.0   

Add:

                 

Major scheduled turnaround expense

    —          1.2        66.4        12.2        34.6            66.4        34.6   

FIFO impacts (favorable)/unfavorable

    (67.9     (31.7     (25.6     1.5        54.3            (46.6     54.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts

    146.1        115.8        548.5        513.6        1,029.9            848.2        1,029.9   

Crude oil throughput(bpd)

    108,226        113,365        103,702        107,070        176,589            162,437        176,589   

Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impact per crude oil throughput barrel

  $ 3.70      $ 2.80      $ 14.49      $ 17.57      $ 21.29          $ 14.31      $ 21.29   

 

 

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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 prospectus in evaluating an investment in our common units.

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 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. Our expected aggregate annual distribution amount for the twelve months ending December 31, 2013 is based on the price assumptions set forth in “Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.” If our price assumptions prove to be inaccurate, our actual distributions for the twelve months ending December 31, 2013 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. 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. In addition, as discussed below, the amount of cash we have to distribute each quarter under our general partner’s current distribution policy will be reduced by (i) maintenance and certain environmental capital expenditures, (ii) payments in respect of debt service and other contractual obligations, and (iii) increases in reserves for future operating or capital needs that our general partner deems necessary or appropriate.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, see “Our Cash Distribution Policy and Restrictions on Distributions.”

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. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined products. 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.

 

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Our profitability is also impacted by the 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. Declines in crude oil differentials can adversely impact refining margins, earnings and cash flows. For example, infrastructure and logistical improvements could result in a reduction of the WTI-Brent differential that has recently provided us with increased profitability. 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. Continued downturns in the economy impact 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.

During 2011 and the first nine months of 2012, favorable crack spreads and access to a variety of price-advantaged crude oils have resulted in higher Adjusted EBITDA and cash flow generation that was higher than usual. We cannot assure you that these favorable conditions will continue and, in fact, crack spreads, refining margins and crude oil prices could decline, possibly materially, at any time. In particular, Enbridge Inc.’s purchase of 50% of the Seaway crude oil pipeline and the recent reversal of the pipeline to make it flow from Cushing to the U.S. Gulf Coast and the Seaway capacity expansion project may contribute to the decline of such favorable conditions by providing mid-continent producers with the ability to transport crude oil to Gulf Coast refiners in an economic manner. Since May 19, 2012, when crude oil began flowing through the Seaway Pipeline from Cushing to the Gulf Coast, volumes have steadily increased towards the current capacity of 150,000 bpd. Work is underway and on schedule to add incremental pumping capacity that would allow the existing Seaway Pipeline to transport up to 400,000 bpd by the first quarter of 2013. Moreover, the planned construction of a loop (twin) of the Seaway Pipeline, a new pipeline designed to parallel the existing right-of-way from Cushing to the Gulf Coast, is expected to more than double Seaway’s capacity to 850,000 bpd by mid-2014. A significant deterioration of the current favorable conditions would have a material adverse effect on our results of operations and ability to pay distributions to our unitholders.

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 non-cash items. For example, 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. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Historically, our business performance has been volatile and seasonal. For instance,

 

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our results of operations for the second and third quarters are generally higher than 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. 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 will 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.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board 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. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

The assumptions underlying the forecast of available cash that we include in “Our Cash Distribution Policy and Restrictions on Distributions—Forecasted Available Cash” are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

Our forecast of available cash set forth in “Our Cash Distribution Policy and Restrictions on Distributions—Forecasted Available Cash” includes our forecast of results of operations and available cash for the twelve months ending December 31, 2013. The forecast has been prepared by the management of CVR Energy on our behalf. Neither our independent registered public accounting firm nor any other independent accountants have examined, compiled or performed any procedures with respect to the forecast, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted annual distribution, in which event the market price of the common units may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. Investors should review the forecast of our results of operations for the twelve months ending December 31, 2013 together with the other information included elsewhere in this prospectus, including “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our refining business faces operating hazards and interruptions, including unplanned maintenance or downtime. We could face potentially significant costs to the extent these hazards or interruptions cause a material decline in production and are not fully covered by our existing insurance coverage. Insurance companies that currently insure companies in the energy industry may cease to do so, may change the coverage provided or may substantially increase premiums in the future.

Our operations are subject to significant operating hazards and interruptions. If our refineries or logistics assets experience a major accident or fire, are damaged by severe weather, flooding or other natural disaster, or are otherwise forced to significantly curtail their operations or shut down, we could incur significant losses which

 

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could have a material adverse effect on our results of operations, financial condition and cash flows, and our ability to pay distributions to our unitholders.

Operations at either or both of our refineries could be curtailed or partially or completely shut down, temporarily or permanently, as the result of a number of circumstances, most of which are not within our control, such as:

 

   

unplanned maintenance, catastrophic events such as a major accident or fire, damage by severe weather, flooding or other natural disaster;

 

   

labor difficulties that result in a work stoppage or slowdown;

 

   

environmental proceedings or other litigation that compel the cessation of all or a portion of the operations;

 

   

state and federal agencies changing interpretations and enforcement of historical environmental rules and regulations; and

 

   

increasingly stringent environmental regulations.

The magnitude of the effect on us of any shutdown will depend on the length of the shutdown and the extent of the plant operations affected by the shutdown. Our refineries require a planned maintenance turnaround every four to five years for each unit. A major accident, fire, flood, or other event could damage our facilities or the environment and the surrounding community or result in injuries or loss of life. For example, the flood that occurred during the weekend of June 30, 2007 shut down our Coffeyville refinery for seven weeks and required significant expenditures to repair damaged equipment. In addition, our Coffeyville refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit on December 28, 2010, which led to reduced crude oil throughput for approximately one month and required significant expenditures to repair. Similarly, the Wynnewood refinery experienced a small explosion and fire in its hydrocracker process unit due to metal failure in December 2010. In addition, on September 28, 2012, a boiler explosion occurred at the Wynnewood refinery, fatally injuring two employees. We have launched an internal investigation into the cause of the boiler explosion, which occurred as operators were restarting a boiler that had been temporarily shut down as part of the refinery’s turnaround process. Damage at the refinery was limited to the boiler. This matter is currently under investigation by the federal Occupational Safety and Health Administration, which could impose penalties if it determines that a violation of Occupational Safety and Health Act (“OSHA”) standards has occurred. Scheduled and unscheduled maintenance could reduce our net income and cash flows during the period of time that any of our units is not operating. Any unscheduled future downtime could have a material adverse effect on our results of operations, financial condition and cash flows.

If we experience significant property damage, business interruption, environmental claims or other liabilities, our business could be materially adversely affected to the extent the damages or claims exceed the amount of valid and collectible insurance available to us. Our property and business interruption insurance policies that cover the Coffeyville refinery have a $1.0 billion limit, with a $2.5 million deductible for physical damage and a 45- to 60-day waiting period (depending on the insurance carrier) before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions of fewer than 45 to 60 days. Our Wynnewood refinery, effective November 1, 2012, is insured with a $1.0 billion limit, a $10.0 million property damage deductible and a 75 days waiting period deductible for business interruption. The property and business interruption insurance policies insuring Coffeyville and Wynnewood assets contain various sub-limits, exclusions, and conditions that could have a material adverse impact on the insurance indemnification of any particular catastrophic loss occurrence. For example, our current property policy contains varying specific sub-limits of $128.5 million (for Coffeyville assets) and $115 million (for Wynnewood assets) for damage caused by flooding. Insurance policy language and terms maintained by us are generally consistent with standards for the energy industry.

The insurance market for the energy industry is highly specialized with a finite aggregate capacity of insurance. It is currently not feasible to purchase insurance limits up to the maximum foreseeable loss occurrence

 

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due to insurance capacity constraints. Our insurance program is renewed annually, and our ability to maintain current levels of insurance is dependent on the conditions and financial stability of the commercial insurance markets serving our industry. Factors that impact insurance cost and availability include, but are not limited to: industry-wide losses, natural disasters, specific losses incurred by us, and the investment returns earned by the insurance industry. The energy insurance market underwrites many refineries having coastal hurricane risk exposure and off shore platforms, thus a significant hurricane occurrence could impact a number of refineries and have a catastrophic impact on the financial results of the entire insurance and reinsurance market serving our 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, which was amended and restated on August 31, 2012 to include the provision of crude oil intermediation services to our Wynnewood refinery. The agreement, whose initial term expires on December 31, 2014, minimizes the amount of in-transit inventory and mitigates crude oil pricing risks by ensuring pricing takes place extremely close to the time when 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 risks may increase, despite any hedging activity in which we may engage, and our liquidity would be negatively impacted due to increased inventory and the negative impact of market volatility.

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

For the Coffeyville refinery, in addition to the crude oil we gather locally in Kansas, Oklahoma, Missouri, and Nebraska, we purchased an additional 80,000 to 90,000 bpd of crude oil to be refined into liquid fuels in 2011. Although the Wynnewood refinery has historically acquired most of its crude oil from Texas and Oklahoma, it also purchases crude oil from other regions. Coffeyville obtains a portion of its non-gathered crude oil, approximately 19% in 2011, from foreign sources and Wynnewood obtained a small amount from foreign sources as well. The majority of these foreign sourced crude oil barrels were derived from Canada. The actual amount of foreign 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 foreign suppliers. Disruption of production in any of these regions for any reason could have a material impact on other regions and our business and 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.

 

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The geographic concentration of our refineries and related assets creates an exposure to the risks of the local economy 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 Renewable Identification Numbers (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 Renewable Fuels Standard 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 U.S. Environmental Protection Agency (“EPA”), has promulgated the Renewable Fuel Standard (“RFS”), which requires refiners to blend “renewable fuels,” such as ethanol, with their petroleum fuels or purchase renewable energy credits, known as renewable identification numbers (“RINs”), in lieu of blending. Under the RFS, the volume of renewable fuels refineries like us are obligated to blend into their finished petroleum products increases annually over time until 2022. Beginning in 2011, our Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. The Wynnewood refinery will be required to comply beginning in 2013. We currently purchase RINs for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. We estimate that we will spend approximately $21.0 million in 2012 on RINs and waiver credits for Coffeyville. Existing laws or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. In the future, we may be required to purchase additional RINs on the open market and waiver credits from EPA in order to comply with the RFS. We cannot currently predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could be material. 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 earning and materially adversely affecting our ability to make distributions.

If we are unable to pass the costs of compliance with RFS on to our customers, our profits would be significantly lower. Moreover, 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

 

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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 any 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 level of indebtedness may increase and reduce our financial flexibility.

On October 23, 2012, CVR Refining, LLC and Coffeyville Finance issued $500 million aggregate principal amount of 6.5% senior notes due 2022. In addition, we entered into the New ABL Credit Facility on December 20, 2012 and expect to enter into the intercompany credit facility in connection with the closing of this offering. In the future, we may incur additional significant indebtedness in order to make future acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:

 

   

a significant portion of our cash flows could be used to service our indebtedness;

 

   

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

   

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;

 

   

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged, and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

 

   

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

   

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

 

   

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, debt service requirements, acquisitions, general corporate or other purposes.

In addition, borrowings under our New ABL Credit Facility and other credit facilities we or our subsidiaries may enter into in the future will bear interest at variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect our cash flow.

 

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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. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.

In addition, the bank borrowing base under the New ABL Credit Facility will be subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial condition and, as a result, our ability to make distributions.

Covenants in our debt instruments could limit our ability to incur additional indebtedness and engage in certain transactions, which could adversely affect our liquidity and our ability to pursue our business strategies.

The indentures governing our notes and the New ABL Credit Facility contain a number of restrictive covenants that will impose significant operating and financial restrictions on us and our subsidiaries and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, among other things, to:

 

   

incur, assume or guarantee additional debt or issue redeemable stock or preferred stock;

 

   

make distributions or prepay, redeem, or repurchase certain debt;

 

   

enter into agreements that restrict distributions from restricted subsidiaries;

 

   

incur liens;

 

   

sell or otherwise dispose of assets, including capital stock of subsidiaries;

 

   

enter into transactions with affiliates; and

 

   

merge, consolidate or sell substantially all of our assets.

The indenture governing our New Notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture contains covenants limiting our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100 million basket plus certain other amounts referred to as “incremental funds” under the indenture. In addition, the New ABL Credit Facility requires us to maintain a minimum excess availability under the facility as a condition to the payment of distributions to our unitholders. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.” Any new indebtedness could have similar or greater restrictions.

A breach of the covenants under the indentures governing our notes or under the New ABL Credit Facility could result in an event of default under the applicable indebtedness. Upon a default, unless waived, the holders of the our notes and the lenders under our New ABL Credit Facility 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 or our subsidiaries’ assets, and force us and our subsidiaries into bankruptcy or liquidation, subject to intercreditor agreements. In addition, any defaults could trigger cross defaults under other

 

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or future credit agreements or indentures. 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. As a result of these restrictions, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities.

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:

 

   

Under extreme market conditions we may not be able to successfully obtain additional financing on favorable terms, or at all, and we may not have sufficient liquidity to operate both the Coffeyville and Wynnewood refineries.

 

   

Market volatility could exert downward pressure on our unit price, which may make it more difficult for us to raise additional capital and thereby limit our ability to grow.

 

   

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 these objectives 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;

 

   

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.

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.

 

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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 that participate in that market, and requires the Commodities Futures Trading Commission (“CFTC”) to institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. 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.

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

Our due diligence associated with asset acquisitions may result in assuming liabilities associated with unknown conditions or deficiencies, as well as known but undisclosed conditions and deficiencies that we may have limited, if any, recourse for cost recovery. In the case of Wynnewood, we have specific language in the Purchase and Sale Agreement that provides us with a limited amount of cost recovery for known, but undisclosed, operational and environmental conditions that had not been specifically scheduled with a very limited time for notice of the condition. Many acquisition agreements have similar terms, conditions and timing of cost recovery that 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;

 

   

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. For example, we have spent approximately $89 million on the most recently completed turnaround at the Coffeyville refinery and we incurred approximately $105.0 million associated with the turnaround for the Wynnewood refinery, which began

 

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in the fourth quarter of 2012 and which we completed in December 2012. These costs do not result in increases in unit capacities, but rather are limited to trying to maintain safe, reliable operations.

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, approval 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. Noncompliance 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.”

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 the Comprehensive Environmental Response, Compensation and Liability Act (“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

 

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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 Resource Conservation and Recovery Act (the “RCRA”) related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Wynnewood refinery is required to conduct investigations to address potential off-site migration of contaminants from the west side of the property. Other known areas of contamination at the Wynnewood refinery have been partially addressed but corrective action has not been completed, and limited portions of the Wynnewood refinery have not yet been investigated to determine whether corrective action is necessary. If significant unknown liabilities are identified at 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 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. For example, WRC’s waste water permit has expired and is in the renewal process. At this time the facility is operating under its expired permit terms and conditions (called a permit shield) until the ODEQ renews the permit. The renewal permit may contain different terms and conditions that would require unplanned or unanticipated costs.

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

Various regulatory and legislative measures to address greenhouse gas emissions (including CO2, methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 “endangerment finding” that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and annually report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring our greenhouse gas emissions and have already reported the

 

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emissions to the EPA for the year ended 2011. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which established new greenhouse gas emissions thresholds that determine when stationary sources, such as our refineries, must obtain permits under Prevention of Significant Deterioration (“PSD”), and Title V programs of the federal Clean Air Act. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the facility would need to evaluate and install best available control technology (“BACT”), to control greenhouse gas emissions. A major modification resulting in a significant expansion of production at one of our refineries that could cause a significant increase in greenhouse gas emissions could necessitate the installation of BACT controls. The EPA’s endangerment finding, Greenhouse Gas Tailoring Rule and certain other greenhouse gas emission rules have been challenged and are subject to extensive litigation. In December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate New Source Performance Standards (“NSPS”) to regulate greenhouse gas emissions from petroleum refineries by November 2012.

At the federal legislative level, Congressional passage of legislation adopting some form of federal mandatory greenhouse gas emission reduction, such as a nationwide cap-and-trade program, does not appear likely at this time, although it could be adopted at a future date. 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 greenhouse gas initiatives to reduce CO2 and other greenhouse gas 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 greenhouse gas 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, and it is unclear whether Kansas still intends to do so.

The implementation of EPA greenhouse gas regulations or potential federal, state or regional programs to reduce greenhouse gas emissions will 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 greenhouse gas emissions program. Increased costs associated with compliance with any future legislation or regulation of greenhouse gas 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 for 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 refinery 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.

 

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Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.

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. The five largest customers of the Coffeyville refinery represented 49% of our petroleum sales for the year ended December 31, 2011, and the five largest customers of the Wynnewood refinery represented approximately 35% of WEC’s sales for the year ended December 31, 2011. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of 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 the gathering assets making up part of our supporting logistics businesses, 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 operations. If we are able to successfully increase the effectiveness of our supporting logistics businesses, including our crude oil gathering operations, 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 our gathering operations 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 operations. 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.

 

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Any businesses or assets that we may acquire in connection with an expansion of our crude oil gathering operations 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 (the “U.S. DOT”) 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.

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;

 

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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 particular, we are in the process of integrating Wynnewood Energy Company, LLC and its subsidiary into CVR Energy’s internal control framework, and testing of these new controls is not yet complete. 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.

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.

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 September 30, 2012, approximately 59% of the employees at the Coffeyville refinery and 63% of the employees at the Wynnewood refinery were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with six Metal Trades Unions (which covers union members who work directly at the Coffeyville refinery) is effective through March 2013, and the collective bargaining agreement with United Steelworkers (which covers CVR Energy’s unionized employees, who work in the terminal and related operations) is effective through March 2015, 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 2015. 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.

 

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Risks Related to the Wynnewood Acquisition

Challenges in operating the Wynnewood Refinery and/or our newly enlarged combined business or difficulties in successfully integrating the businesses of the Partnership and WEC within the expected time frame could adversely affect our future results of operations following the Wynnewood Acquisition.

As a result of the Wynnewood Acquisition, we doubled our number of refineries from one to two and increased our refining throughput capacity by over 50%. The ultimate success of the Wynnewood Acquisition will depend, in large part, on our ability to successfully expand the scale and geographic scope of our operations across state lines and to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the our business and WEC. To realize these anticipated benefits, the business of WEC must be successfully integrated into ours. This integration will be complex and time-consuming.

The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in our not achieving the anticipated benefits of the merger. Potential difficulties that may be encountered in the integration process include the following:

 

   

the inability to successfully integrate the business of WEC into ours in a manner that permits the combined company to achieve the full revenue and cost savings anticipated to result from the merger;

 

   

complexities associated with managing the larger, more complex, combined business;

 

   

integrating personnel from the two companies while maintaining focus on providing consistent, high-quality service;

 

   

potential unknown liabilities and unforeseen expenses associated with the Wynnewood Acquisition;

 

   

performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the Wynnewood Acquisition and integrating WEC’s operations;

Even if we are able to successfully integrate the business operations of WEC, we may not realize the full benefits of the expected synergies, cost savings, innovation and operational efficiencies within the anticipated time frame or at all.

We have incurred and expected to continue to incur substantial expenses related to the Wynnewood Acquisition and the integration of WEC.

We have incurred and expected to continue to incur substantial expenses in connection with the Wynnewood Acquisition and the integration of WEC. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated, including purchasing, accounting and finance, sales, billing, payroll, pricing, revenue management, maintenance, marketing and benefits. While we have assumed that a certain level of expenses would be incurred, there are many factors beyond our control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These expenses could, particularly in the near term, exceed the savings that we expect to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings. These integration expenses likely will result in taking significant charges against earnings following the completion of the Wynnewood Acquisition, and the amount and timing of such charges are uncertain at present.

Risks Inherent in an Investment in Us

The board of directors of our general partner will adopt 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.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders, beginning with the quarter ending March 31, 2013. As

 

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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.

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 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. See “Our Cash Distribution Policy and Restrictions on Distributions.”

We rely primarily on the executive officers of CVR Energy to manage most aspects of our business and affairs pursuant to a services agreement, which CVR Energy can terminate at any time following the one year anniversary of this offering.

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, business operations, legal, finance and other key back-office and mid-office personnel. Following the one year anniversary of this offering, 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 nor that such provision will be on terms that are acceptable. If CVR Energy elected to terminate the service agreement on 180 days’ notice following the one year anniversary of this offering, we might not be able to find qualified individuals to serve as our executive officers within such 180-day period.

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 spent 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 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.

 

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

 

   

Neither our partnership agreement nor any other agreement will require 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 Icahn Enterprises, 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 will control the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner will decide 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.

See “Conflicts of Interest and Fiduciary Duties.”

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:

 

   

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 will be 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.

 

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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:

 

  (A) 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

 

  (B) Approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. See “Description of Our Common Units—Transfer of Common Units.”

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

Upon the consummation of this offering, CVR Energy will have 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. See “Management—Management of CVR Refining, LP.” 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 Icahn Enterprises, 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 95% 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. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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. See “The Partnership Agreement—Call Right.”

Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors and will 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 will 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, will be chosen entirely by CVR Energy as the indirect owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we will 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 will have no practical ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished.

 

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Following the closing of this offering, CVR Energy will indirectly own approximately 86.4% of our common units (or approximately 84.4% if the underwriters exercise their option to purchase additional common units in full), which means holders of common units purchased in this offering 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, Icahn Enterprises has indicated that it or its affiliates may purchase in this offering up to $100.0 million, or up to approximately 4,000,000 (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common units, in which case they would directly own, upon completion of the offering, approximately 2.7% 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 you.

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 you. See “Our Cash Distribution Policy and Restrictions on Distributions,” “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.”

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, following the one-year anniversary of the closing date of this offering, it may do upon 180 days’ notice.

There is no existing market for our common units, and we do not know if one will develop to provide you with adequate liquidity. If our unit price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our common units. If an active trading market does not develop, you may have difficulty selling any of our common units that you buy. The initial public offering price for the common units will be determined by negotiations between us and the underwriters and may

 

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not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common units at prices equal to or greater than the price paid by you in this offering. The market price of our common units may be influenced by many factors including:

 

   

our operating and financial performance;

 

   

quarterly variations in our financial indicators, such as net (loss) earnings per unit, net earnings (loss) and revenues;

 

   

the amount of distributions we make and our earnings or those of other companies in our industry or other publicly traded partnerships;

 

   

strategic actions by our competitors;

 

   

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

sales of our common units by us or other unitholders, or the perception that such sales may occur;

 

   

changes in accounting principles;

 

   

additions or departures of key management personnel;

 

   

actions by our unitholders;

 

   

general market conditions, including fluctuations in commodity prices; and

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance.

As a result of these factors, investors in our common units may not be able to resell their common units at or above the initial offering price. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of our common units, regardless of our operating performance.

You will incur immediate and substantial dilution in net tangible book value per common unit.

The initial public offering price of our common units is substantially higher than the pro forma net tangible book value of our outstanding units. As a result, if you purchase common units in this offering, you will incur immediate and substantial dilution in the amount of $15.50 per common unit. This dilution results primarily because the assets contributed by CVR Energy and its affiliates are recorded at their historical costs, and not their fair value, in accordance with GAAP. See “Dilution.”

We may issue additional common units and other equity interests without your approval, which would dilute your existing ownership interests.

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.

 

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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.

There will be 147,600,000 common units outstanding following this offering. 20,000,000 common units are being sold to the public in this offering (or 23,000,000 common units if the underwriters exercise their option to purchase additional common units in full), 127,587,540 common units will be owned by CVR Refining Holdings following this offering (or 124,587,540 common units if the underwriters exercise their option to purchase additional common units in full) and CVR Refining Holdings Sub, LLC, a wholly-owned subsidiary of CVR Refining Holdings, will own 12,460 common units. In addition, as discussed above, if Icahn Enterprises or its affiliates purchase $100.0 million, or approximately 4,000,000 (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common units, they would directly own approximately 2.7% of our common units. The number of common units available for sale to the general public will be reduced to the extent Icahn Enterprises or its affiliates purchase such common units. The common units sold in this offering will be freely transferable without restriction or further registration under the Securities Act of 1933 (the “Securities Act”), by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act.

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 this offering, we will enter into a registration rights agreement with Icahn Enterprises, 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 Icahn Enterprises, CVR Refining Holdings or CVR Refining Holdings Sub, LLC.

In connection with this offering, we, CVR Refining Holdings, our general partner and our general partner’s directors and executive officers will enter into lock-up agreements, pursuant to which they will agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any of our common units until 180 days from the date of this prospectus, subject to extension in certain circumstances. Following termination of these lockup agreements, all units held by CVR Refining Holdings, our general partner and their affiliates will be freely tradable under Rule 144, subject to the volume and other limitations of Rule 144. See “Common Units Eligible for Future Sale.”

We will incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership. We estimate that we will incur approximately $5.0 million of estimated incremental costs per year, some of which will be direct charges associated with being a publicly traded partnership, and some of which will be allocated to us by CVR Energy; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 

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Following this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We expect these requirements will increase our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

As a publicly traded partnership we qualify for, and are relying on, certain exemptions from the New York Stock Exchange’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.

As a result of these exemptions, our general partner’s board of directors will not be comprised of a majority of independent directors, our general partner may choose not to have a compensation committee or to have a compensation committee that does not consist entirely of independent directors, and our general partner’s board of directors does not currently intend to establish a nominating/corporate governance committee. 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. See “Management.”

We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. Under current rules, we will be required to comply with Section 404 in our annual report for the year ending December 31, 2013. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board (the “PCAOB”), rules and regulations that remain unremediated. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. As a publicly traded partnership, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. If we do not implement improvements to our disclosure controls and procedures or to our internal controls in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal controls over financial

 

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reporting. This may subject us to adverse regulatory consequences or a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our independent registered public accounting firm reports a material weakness in our internal controls, if we do not develop and maintain effective controls and procedures or if we are otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of our financial statements or other negative reaction to our failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of our common units. In addition, if we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and the price of our common units may be adversely affected.

Tax Risks

In addition to reading the following risk factors, please read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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 Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

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 federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity level taxation.

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

The tax treatment of publicly-traded partnerships or an investment in our 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 us, or an investment in our 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 the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

 

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You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

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 federal income tax purposes.

We will be considered to have terminated as a partnership for 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 interest will be counted only once. Immediately following this offering, our sponsor will directly and indirectly own 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 federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for 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 termination occurred. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your 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 depreciation and depletion deductions and certain other items. In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “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 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, and non-U.S. persons will be required to file U.S. federal 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.

 

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

The IRS may adopt positions that differ from the positions we take. 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 by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

We will 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 the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopt.

We will 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 units on the first day of each month, instead of on the basis of the date a particular 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, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully 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, he would no longer be treated for 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 is no tax concept of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for 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 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 loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

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You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you will likely 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 property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and/or conduct business in the states of Arkansas, Iowa, Kansas, Missouri, Nebraska, Oklahoma, Texas and South Dakota. These states, other than Texas and South Dakota, currently impose a personal income tax. These states, other than South Dakota, also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” “attempt,” “appears,” “forecast,” “outlook,” “estimate,” “project,” “potential,” “may,” “will,” “are likely” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. All statements herein about our forecast of available cash and our forecasted results for the twelve months ending December 31, 2013 constitute forward-looking statements. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate, and any and all of our forward-looking statements in this prospectus may turn out to be inaccurate.

Forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Such risks and uncertainties include, among other things:

 

   

our ability to make cash distributions on the common units;

 

   

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

 

   

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

 

   

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

 

   

the effects of transactions involving forward and derivative instruments;

 

   

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

 

   

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

 

   

the level of competition from other petroleum refiners;

 

   

changes in our credit profile;

 

   

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

 

   

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

 

   

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;

 

   

our dependence on significant customers;

 

   

our potential inability to obtain or renew permits;

 

   

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

 

   

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

 

   

our lack of asset diversification;

 

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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;

 

   

our ability to continue to license the technology used in our operations;

 

   

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

 

   

our significant indebtedness;

 

   

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

 

   

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

 

   

restrictions in our debt agreements;

 

   

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 NYSE corporate governance requirements;

 

   

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

 

   

risks relating to our relationships with CVR Energy;

 

   

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

 

   

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

 

   

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

 

   

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

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs, forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

 

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USE OF PROCEEDS

Based on an assumed initial offering price of $25.00 per common unit, we expect to receive net proceeds of approximately $469.0 million from the sale of 20,000,000 common units offered by this prospectus, after deducting the estimated underwriting discounts and commissions, offering expenses and structuring fees payable by us. We intend to use the net proceeds of this offering in the following manner:

 

   

$255.0 million to repurchase the 10.875% senior secured notes due 2017 issued by Coffeyville Resources (the “Second Lien Notes”) and pay associated accrued interest;

 

   

$160.0 million to prefund certain maintenance and environmental capital expenditures through 2014; and

 

   

$54.0 million to fund the turnaround expenses of our Wynnewood refinery in the fourth quarter of 2012.

If Icahn or its affiliates purchase $100.0 million of common units in this offering, then our net proceeds will increase by approximately $5.5 million.

Pursuant to the Reorganization Agreement, Coffeyville Resources, on behalf of CVR Refining Holdings, will, if necessary, contribute to us an amount of cash such that we will have approximately $340 million of cash on hand at the closing of this offering, including the proceeds of this offering (other than the $255.0 million used to repurchase the Second Lien Notes). If such amount of cash on hand at the closing of this offering exceeds $340 million, we will distribute the excess to Coffeyville Resources.

Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $18.9 million (assuming no exercise of the underwriters’ option to purchase additional common units).

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $70.9 million based on an assumed initial offering price of $25.00 per common unit, if exercised in full) will be used to make a distribution to CVR Refining Holdings. If the underwriters do not exercise their option to purchase additional common units, we will issue 3,000,000 common units to CVR Refining Holdings at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to CVR Refining Holdings. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding. Please read “Underwriting.”

 

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CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of September 30, 2012:

 

   

on an actual combined basis; and

 

   

on a pro forma combined basis to reflect the Transactions described under “Prospectus Summary—The Transactions,” including application of the net proceeds from this offering as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the unaudited historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of September 30, 2012  
     Actual      Pro Forma  
     (in thousands)  

Cash and cash equivalents

   $ 79,550       $ 340,000   
  

 

 

    

 

 

 

Debt:

     

Asset-based revolving credit facility(1)

   $ —         $ —     

Intercompany credit facility(2)

     —           —     

9.0% senior secured notes due 2015

     453,654         —     

10.875% senior secured notes due 2017

     220,827         —     

Capital lease obligations

     52,510         52,510   

6.5% senior notes due 2022

     —           500,000   
  

 

 

    

 

 

 

Total debt

   $ 726,991       $ 552,510   
  

 

 

    

 

 

 

Equity:

     

Divisional equity

   $ 937,694       $ —     

Partners’ equity in CVR Refining, LP:

     

Common units—CVR Refining Holdings

     —           932,495   

Common units—public

     —           469,000   
  

 

 

    

 

 

 

Total equity

   $ 937,694       $ 1,401,495   
  

 

 

    

 

 

 

Total capitalization

   $ 1,664,685       $ 1,954,005   
  

 

 

    

 

 

 

 

(1) On December 20, 2012, we entered into the New ABL Credit Facility that amends and restates Coffeyville Resources’ ABL credit facility. As of September 30, 2012, no amounts were outstanding under the ABL credit facility and Coffeyville Resources had availability of approximately $372.8 million and had letters of credit outstanding of approximately $27.2 million.
(2) We expect to enter into a $150 million senior unsecured revolving credit facility with Coffeyville Resources in connection with the closing of this offering.

 

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DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Our pro forma combined net tangible book value as of September 30, 2012, excluding the net proceeds of this offering, was approximately $932.5 million, or approximately $ 7.31 per unit. Pro forma combined net tangible book value per unit gives effect to the pro forma adjustments described in the notes to the unaudited pro forma combined financial statements included elsewhere in this prospectus (other than the issuance of common units in this offering and the receipt of the net proceeds from this offering as described under “Use of Proceeds”) and represents the amount of pro forma combined tangible assets less pro forma combined total liabilities (excluding the net proceeds of this offering), divided by the pro forma number of units outstanding (excluding the units issued in this offering).

Dilution in combined net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma combined net tangible book value per unit immediately after this offering. After giving effect to the sale of 20,000,000 common units in this offering at an initial public offering price of $25.00 per common unit, and after deduction of the estimated underwriting discounts and commissions, estimated offering expenses and structuring fees payable by us, our pro forma combined net tangible book value as of September 30, 2012 would have been approximately $1,401.5 million, or $9.50 per unit. This represents an immediate increase in combined net tangible book value of $2.19 per unit to our existing unitholders and an immediate combined pro forma dilution of $15.50 per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

 

Assumed initial public offering price per common unit

     $ 25.00   

Combined net tangible book value per common unit before the offering(1)

    7.31      

Increase in net combined tangible book value per common unit attributable to purchasers in the offering

    2.19      

Less: Pro forma combined net tangible book value per common unit after the offering(2)

       (9.50
    

 

 

 

Immediate dilution in combined net tangible book value per common unit to purchasers in the offering(3)

       15.50   
    

 

 

 

 

(1) Determined by dividing the combined net tangible book value of the contributed assets and liabilities by the number of common units to be issued to CVR Refining Holdings for its contribution of assets and liabilities to us.
(2) Determined by dividing our combined pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering by the total number of common units outstanding after this offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus ($ in millions):

 

     Units     Total Consideration  
     Number      Percent     Amount     Percent  

CVR Refining Holdings(1)

     127,600,000         86.4   $ 932,495,000 (2)      66.5

New investors

     20,000,000         13.6     469,000,000 (3)      33.5
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

     147,600,000         100   $ 1,401,495,000        100
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) The number of units includes 12,460 common units issued to CVR Refining Holdings’ wholly owned subsidiary, CVR Refining Sub, LLC.
(2) Reflects the value of the assets to be contributed to us by Coffeyville Resources recorded at historical cost in accordance with GAAP, as adjusted for capital account adjustments.
(3) Reflects the net proceeds of this offering after deducting the underwriting discounts and commissions, estimated offering expenses and structuring fees payable by us, and assumes the underwriter’s option to purchase additional common units is not exercised.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy and restrictions on distributions in conjunction with the specific assumptions upon which our cash distribution policy is based. See “—Forecast Assumptions and Considerations” below. For additional information regarding our combined historical and pro forma operating results, you should refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited historical combined financial statements, our unaudited historical combined financial statements and our unaudited pro forma combined financial statements included elsewhere in this prospectus. In addition, you should read “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a policy pursuant to which we will distribute all of the available cash we generate each quarter, beginning with the quarter ending March 31, 2013. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service maintenance and environmental capital expenditures, and reserves for expenses associated with our major scheduled turnarounds. The board of directors may also determine that it is appropriate to reserve cash for future operating or capital needs. 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 from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions; Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

 

   

Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter all of the available cash we generate each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

 

   

Subject to certain exceptions, the indenture governing the New Notes and the New ABL Credit Facility, as well as future debt agreements, will place restrictions on our ability to pay cash distributions. Specifically, the indenture contains financial covenants that limit our ability to make distributions if our fixed charge coverage ratio is below a specified level and the New ABL credit facility requires us to maintain a minimum excess availability under the facility as a condition to the payment of distributions to our unitholders. Should we be unable to satisfy these restrictions under our indenture or if we are otherwise in default under our

 

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indenture, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

 

   

Our business performance is expected to be volatile, and our cash flows are expected to be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually.

 

   

Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase quarterly distributions over time. Furthermore, none of our limited partnership interests, including those held by CVR Refining Holdings, will be subordinate in right of distribution payment to the common units sold in this offering.

 

   

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

   

Prior to making any distributions on our units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

 

   

Under Section 17-607 of the Delaware Act, we may not make a distribution to our limited partners if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to make distributions to our unitholders due to a number of factors that would adversely affect us, including but not limited to decreases in net sales or increases in operating expenses, principal and interest payments on debt, working capital requirements, capital expenditures or anticipated cash needs. See “Risk Factors” for information regarding these factors.

We do not have any operating history as an independent entity upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending December 31, 2013, we may be unable to pay the forecasted distribution or any amount on our common units.

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. Therefore, our growth, if any, may not be comparable to those businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, any future growth may be slower than our historical growth. We expect that we will rely upon external financing sources in large part, including bank borrowings and issuances of debt and equity interests, to fund our growth capital expenditures. To the extent we are unable to finance growth externally, our distribution policy could significantly impair our ability to grow.

We expect to pay our distributions within sixty days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through March 31, 2013.

In the sections that follow, we present the following two tables:

 

   

“CVR Refining, LP Unaudited Pro Forma Combined Available Cash for the Year Ended December 31, 2011 and the Twelve Months Ended September 30, 2012,” in which we present our estimate of the

 

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amount of pro forma combined available cash we would have had for the year ended December 31, 2011 and the twelve months ended September 30, 2012, in each case, based on our unaudited pro forma combined financial statements included elsewhere in this prospectus; and

 

   

“CVR Refining, LP Estimated Available Cash for the Twelve Months Ending December 31, 2013,” in which we present our unaudited forecast of available cash for the twelve months ending December 31, 2013.

Unaudited Pro Forma Combined Available Cash

We believe that we would have generated pro forma combined available cash during the year ended December 31, 2011 and the twelve months ended September 30, 2012 of $638.8 million and $844.2 million, respectively. Based on the cash distribution policy we expect our board of directors to adopt, this amount would have resulted in an aggregate annual distribution per common unit equal to $4.33 for the year ended December 31, 2011 and $5.72 for the twelve months ended September 30, 2012.

Pro forma combined available cash reflects the payment of incremental general and administrative expenses we expect that we will incur as a publicly traded limited partnership, such as costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses will be approximately $5.0 million per year. The estimated incremental general and administrative expenses are reflected in our pro forma combined available cash but are not reflected in our unaudited pro forma combined financial statements.

The pro forma combined financial statements, from which pro forma combined available cash is derived, do not purport to present our results of operations had the transactions contemplated below actually been completed as of the date indicated. Furthermore, available cash is a cash accounting concept, while our unaudited pro forma combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma combined available cash stated above in the manner described in the table below. As a result, the amount of pro forma combined available cash should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed and completed the transactions contemplated below in earlier periods.

 

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The following table illustrates, on a pro forma combined basis for the year ended December 31, 2011, and for the twelve months ended September 30, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that the Transactions and the acquisition of WEC had occurred on January 1, 2011:

CVR Refining, LP

Unaudited Pro Forma Combined Available Cash for the Year Ended December 31, 2011 and the Twelve

Months Ended September 30, 2012

 

     Pro Forma Combined  
     Year Ended
December 31,
2011
    Twelve Months
Ended  September 30,
2012
 
     ($ in millions except per unit data)  

Statement of Operations Data:

  

Net sales

   $ 7,398.3      $ 8,049.3   

Operating costs and expenses:

    

Cost of product sold

     6,126.0        6,538.7   

Direct operating expenses

     345.0        379.7   

Selling, general and administrative expense

     72.7        95.6   

Depreciation and amortization

     98.9        106.6   
  

 

 

   

 

 

 

Operating income

   $ 755.7      $ 928.7   

Other income (expense):

    

Interest expense and other financing costs

     (41.7     (42.0

Realized gain (loss) on derivatives, net

     (49.0     (88.2

Unrealized gain (loss) on derivatives, net

     85.4        (67.0

Loss on extinguishment of debt

     (2.1     —     

Other income, net

     0.7        0.7   
  

 

 

   

 

 

 

Net income

   $ 749.0      $ 732.2   

Adjustments to reconcile net income to Adjusted EBITDA:

    

Interest expense and other financing costs

     41.7        42.0   

Depreciation and amortization

     98.9        106.6   
  

 

 

   

 

 

 

EBITDA subtotal

   $ 889.6      $ 880.8   

FIFO impacts (favorable) unfavorable

     (46.6     (21.4

Share-based compensation

     8.9        16.5   

Loss of disposition of assets

     2.5        1.0   

Loss on extinguishment of debt

     2.1        —     

Wynnewood acquisition transaction fees and integration expense

     5.2        15.5   

Major scheduled turnaround expenses

     66.4        88.8   

Unrealized (gain) loss on derivatives, net

     (85.4     66.9   
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 842.7      $ 1,048.1   

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:

    

Less:

    

Incremental general and administrative expenses

     5.0        5.0   

Maintenance environmental capital expenditures

     69.4        97.7   

Growth capital expenditures

     18.2        25.1   

Increase in reserves for maintenance/environmental capital expenditures

     125.0        125.0   

Increase in reserves for future turnarounds(a)

     35.0        35.0   

Cash interest expense, net

     38.9        38.9   

Plus:

    

Use of cash on hand to fund maintenance/environmental capital expenditures

     69.4        97.7   

Draw on $150 million senior unsecured revolving credit facility to fund growth capital expenditures

     18.2        25.1   
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 638.8      $ 844.2   
  

 

 

   

 

 

 

Common units outstanding for the period presented
(in millions)

     147.6        147.6   

Estimated cash available for distribution per unit

   $ 4.33      $ 5.72   

Other:

    

Fixed charge coverage ratio(b)

     19.5x        24.3x   

 

(a)

Following this offering, the board of directors of our general partner intends to reserve amounts to fund the expenses associated with major turnarounds. Following this offering, we expect to reserve approximately

 

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$35.0 million of cash each year for major turnaround expenses of our two refineries, which occur approximately every four years. The presentation above reflects a reserve of $35.0 million during each of the periods presented as if we had been reserving these amounts.

(b) The indenture governing our senior notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100 million basket plus certain other amounts referred to as “incremental funds” under the indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

Forecasted Available Cash

During the twelve months ending December 31, 2013, we estimate that we will generate $696.9 million of available cash. In “—Forecast Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The available cash discussed in the forecast should not be viewed as management’s projection of the actual available cash that we will generate during the twelve months ending December 31, 2013. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate available cash and how we calculate forecasted available cash, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.

We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below in the table entitled “CVR Refining, LP Estimated Available Cash for the Twelve Months Ending December 31, 2013” to present our expectations regarding our ability to generate $696.9 million of available cash for the twelve months ending December 31, 2013. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management team of our general partner, all of whom are employed by CVR Energy, as of the date of its preparation, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient available cash to allow us

 

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to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending December 31, 2013 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated available cash for the twelve months ending December 31, 2013. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Forecast Assumptions and Considerations.”

Neither our independent registered public accounting firm, independent auditors, nor any other independent registered public accounting firm, has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical combined financial information. These reports do not extend to the tables and the related forecasted information contained in this section and should not be read to do so.

The following table illustrates the amount of cash that we estimate that we will generate for the twelve months ending December 31 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending December 31, 2013 in the table below are estimates. Forecasted NYMEX 2:1:1 crack spread, realized 2:1:1 crack spread, WTI prices, realized refining gross operating margin per barrel and direct operating expenses per barrel represent weighted averages estimated over the stated period.

CVR Refining, LP

Estimated Available Cash for the Twelve Months Ending December 31, 2013

 

    Three Months Ending     Twelve Months
Ending
December 31,
2013
 
    March 31,
2013
    June 30,
2013
    September 30,
2013
    December 31,
2013
   
    (unaudited) (dollars in millions except per barrel data)  

Operating Data:

         

Throughput (bpd):

         

Sweet

    120,732        140,111        140,175        140,485        135,389   

Medium

    18,763        18,750        18,686        18,376        18,721   

Heavy Sour

    15,505        18,639        18,639        18,639        17,842   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total crude oil throughput

    155,000        177,500        177,500        177,500        171,952   

Feedstocks/Blendstocks

    16,256        11,211        11,680        19,333        14,620   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total throughput

    171,256        188,711        189,180        196,833        186,572   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Refinery product yields (bpd):

         

Gasoline

    85,939        87,896        89,369        100,070        90,853   

Distillates

    65,822        77,641        76,300        75,604        73,875   

Other

    17,325        20,535        20,748        18,530        19,292   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total production (excluding internally produced fuel)

    169,086        186,072        186,417        194,204        184,020   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Forecasted NYMEX 2:1:1 crack spread (per barrel)

  $ 28.65      $ 29.43      $ 26.85      $ 25.07      $ 27.50   

Forecasted WTI (per barrel)

  $ 95.56      $ 95.59      $ 94.98      $ 94.05      $ 95.04   

Refining margin per crude oil throughput barrel(a)

  $ 26.38      $ 23.35      $ 18.82      $ 18.96      $ 21.70   

 

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    Three Months Ending     Twelve Months
Ending
December 31,
2013
 
    March 31,
2013
    June 30,
2013
    September 30,
2013
    December 31,
2013
   
    (unaudited) (dollars in millions except per barrel data)  

Refining margin per crude oil throughput barrel adjusted for FIFO impact(a)

  $ 24.77      $ 23.39      $ 19.37      $ 19.73      $ 21.70   

Direct operating expense excluding major turnaround expense per crude oil throughput barrel(b)

  $ 5.81      $ 5.02      $ 4.87      $ 4.83      $ 5.11   

Statement of operations data:

         

Net sales

  $ 1,798.7      $ 2,032.4      $ 1,975.1      $ 2,006.1      $ 7,812.3   

Operating costs, expenses and other:

         

Cost of sales

  $ 1,430.8      $ 1,655.3      $ 1,667.8      $ 1,696.5      $ 6,450.4   

Direct operating expenses

    81.0        81.2        79.6        78.9        320.7   

Turnaround and related expenses

    —          —          —          —          —     

Depreciation & amortization

    28.3        28.6        29.1        29.6        115.6   

Selling, general & administrative expenses

    20.9        20.1        19.4        19.8        80.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  $ 237.7      $ 247.2      $ 179.2      $ 181.3      $ 845.4   

Interest expense and other financing costs

    (9.8     (9.9     (10.0     (10.0     (39.7

Realized gain (loss) on derivatives, net

    (26.6     (16.9     (18.7     (11.7     (73.9

Unrealized gain (loss) on derivatives, net

    26.6        16.9        18.7        11.7        73.9   

Other income

    .3        .2        .3        .6        1.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 228.2      $ 237.5      $ 169.5      $ 171.9      $ 807.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjustments to reconcile net earnings to Adjusted EBITDA:

         

Interest expense and other financing costs

  $ 9.8      $ 9.9      $ 10.0      $ 10.0      $ 39.7   

Depreciation & amortization

    28.3        28.6        29.1        29.6        115.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA subtotal

  $ 266.3      $ 276.0      $ 208.6      $ 211.5      $ 962.4   

FIFO impacts (favorable) unfavorable

    (22.5     0.7        9.0        12.7        (0.1

Unrealized (gain) loss on derivatives, net

    (26.6     (16.9     (18.7     (11.7     (73.9

Share-based compensation

    3.2        3.3        3.0        2.9        12.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA (c)

  $ 220.4      $ 263.1      $ 201.9      $ 215.4      $ 900.8   

Adjustments to reconcile Adjusted EBITDA to estimated cash available for distribution:

         

Less:

         

Incremental general and administrative expenses

  $ 1.3      $ 1.2      $ 1.3      $ 1.2      $ 5.0   

Cash interest expense (net)

    —          19.3        —          19.6        38.9   

Maintenance capital expenditures

    16.5        15.5        8.8        48.7        89.5   

Environmental capital expenditures

    22.4        23.9        22.9        25.5        94.7   

Growth capital expenditures

    5.7        11.6        10.8        19.4        47.5   

Increase in reserves for environmental and maintenance capital expenditures

    31.2        31.3        31.2        31.3        125.0   

Increase in reserves for future turnarounds(d)

    8.7        8.8        8.7        8.8        35.0   

Plus:

         

Use of cash on hand to fund environmental and maintenance capital expenditures

  $ 38.9      $ 39.4      $ 31.7      $ 74.2      $ 184.2   

 

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    Three Months Ending     Twelve Months
Ending
December 31,
2013
 
    March 31,
2013
    June 30,
2013
    September 30,
2013
    December 31,
2013
   
    (unaudited) (dollars in millions except per barrel data)  

Draw on $150mm senior unsecured credit facility to fund growth capital expenditures

    5.7        11.6        10.8        19.4        47.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated Cash Available for Distribution

  $ 179.2      $ 202.5      $ 160.7      $ 154.5      $ 696.9   

Implied cash distributions based on available cash:

         

Cash distributions to common unitholders

  $ 179.2      $ 202.5      $ 160.7      $ 154.5      $ 696.9   

Common units outstanding as of the record date for the period presented (in millions)

    147.6        147.6        147.6        147.6        147.6   

Cash available for distribution per unit

  $ 1.2141      $ 1.3720      $ 1.0888      $ 1.0467      $ 4.7215   

Sensitivity Analyses:

         

Changes in estimated cash available for distribution upon the following changes:

         

$1/bbl increase in NYMEX 2:1:1 crack spread

          $ 60.2   

Impact of $1/bbl increase in NYMEX 2:1:1 crack spread on derivative contracts (e)

          $ (22.7

$1/bbl increase in realized crude oil differential to WTI

          $ 67.8   

1,000 bpd increase in throughput

          $ 6.9   

Indenture:

         

Fixed charge coverage ratio (f)

            23.1

Please read the accompanying summary of significant accounting policies and forecast assumptions.

 

(a)

Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and costs of product sold (exclusive of depreciation and amortization) divided by our refineries’ crude oil throughput volumes for the respective periods presented. Refining margin per crude oil throughput barrel is a non-GAAP performance measure that should not be substituted for gross profit or operating income. Management believes this measure is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Our calculation of refining margin per crude oil throughput barrel may differ from similar calculation of other companies in our industry, thereby limiting its usefulness as a comparative measure. We use refining margin per crude oil throughput barrel as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability. Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) adjusted for FIFO impacts. Refining margin adjusted for FIFO impact is a non-GAAP measure that we believe is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of product sold (taking into account the impact of our utilization of FIFO) that we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable

 

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FIFO impacts when crude oil prices decrease. A reconciliation of net sales to refining margin per crude oil throughput barrel adjusted for FIFO impact is included below:

 

     Three Months Ending      Twelve Months
Ending
December 31,
2013
 
     March 31,
2013
    June 30,
2013
     September 30,
2013
     December 31,
2013
    
     (unaudited) (dollars in millions except per barrel data)  

Net sales

   $ 1,798.7      $ 2,032.4       $ 1,975.1       $ 2,006.1       $ 7,812.3   

Less: cost of product sold (exclusive of depreciation and amortization)

     1,430.8        1,655.3         1,667.8         1,696.5         6,450.4   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Refining margin

     367.9        377.1         307.3         309.6         1,361.9   

FIFO impacts (favorable) unfavorable

     (22.5     0.7         9.0         12.7         (0.1

Refining margin adjusted for FIFO impact

     345.4        377.8         316.3         322.3         1,361.8   

Crude oil throughput (bpd)

     155,000        177,500         177,500         177,500         171,952   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Refining margin per crude oil throughput barrel

   $ 26.38      $ 23.35       $ 18.82       $ 18.96       $ 21.70   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Refining margin per crude oil throughput barrel adjusted for FIFO impact

   $ 24.77      $ 23.39       $ 19.37       $ 19.73       $ 21.70   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

 

(b) Direct Operating Expenses (Excluding Major Turnaround Expenses) Per Crude Oil Throughput Barrel. Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel is a measurement calculated by excluding major scheduled turnaround expenses from direct operating expenses (exclusive of depreciation and amortization) divided by our refineries’ crude oil throughput volumes for the respective periods presented. We do not forecast any major scheduled turnaround expense in the twelve months ending December 31, 2013, and therefore, the metric is equal to direct operating expenses per crude oil throughput barrel for each of the periods presented. Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel is a supplemental measure of our performance that is not required by, nor presented in accordance with, GAAP. Management believes direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput most directly represents ongoing direct operating expenses at our refineries.

 

(c) For a definition of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

 

(d) Following this offering, the board of directors of our general partner intends to reserve amounts to fund the expenses associated with major turnarounds. Following this offering, we expect to reserve approximately $35 million of cash each year for major turnaround expenses of our two refineries, which occur approximately every four years. 

 

(e) We have approximately 62,000 barrels per day of gasoline and diesel hedged through 2013 at a weighted average gross margin of $26.13 per barrel.

 

(f) The indenture governing our senior notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition the indenture limits our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100 million basket plus certain other amounts referred to as “incremental funds” under the indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

 

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Forecast Assumptions and Considerations

General

Based upon the specific assumptions outlined below, we expect to generate available cash in an amount sufficient to allow us to pay $4.7215 per common unit on all of our outstanding units for the twelve months ending December 31, 2013.

While we believe that these assumptions are reasonable in light of our management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Basis of Presentation

The accompanying financial forecast and summary of significant forecast assumptions present our forecasted results of operations for the twelve months ending December 31, 2013, assuming that the Transactions (as defined in “Summary—The Transactions”) had occurred as of January 1, 2013. All comparisons shown below for the year ended December 31, 2011 and twelve months ended September 30, 2012 are pro forma for the WEC acquisition.

Utilization

The combined crude oil throughput capacity of our two refineries is approximately 185,000 bpd. We have assumed that the refineries will operate at an average total crude oil throughput of approximately 172,000 bpd during the twelve months ending December 31, 2013 and have assumed no significant downtime during such period. Pro forma for the Wynnewood acquisition, for the year ended December 31, 2011 and the twelve months ended September 30, 2012, our refineries had throughput of approximately 162,400 bpd and 169,200 bpd, respectively. Utilization was adversely impacted in both periods due to downtime associated with a scheduled turnaround at our Coffeyville refinery which was completed in two phases. The first phase of the Coffeyville turnaround was completed in the fourth quarter of 2011 and the second phase was completed in the first quarter of 2012. We completed a turnaround at our Wynnewood refinery in December 2012. Accordingly, this turnaround will not impact utilization during the twelve months ended December 31, 2013.

Net Sales

We project net sales of approximately $7.8 billion over the twelve months ending December 31, 2013. Pro forma for the Wynnewood acquisition, we generated net sales of approximately $7.4 billion during the year ended December 31, 2011 and $8.0 billion during the twelve months ended September 30, 2012.

Gasoline. We estimate net gasoline sales based on forecast future product prices multiplied by the number of barrels of gasoline we estimate that we will produce and sell during the twelve months ending December 31, 2013. We forecast that we will produce and sell approximately 33.2 million barrels of gasoline at a weighted average price of $114.59 per barrel during the twelve months ending December 31, 2013. We project the weighted average selling price of gasoline based on projected estimates of WTI and the projected Group 3 gasoline benchmark price differential to WTI. We assumed a weighted average gasoline price premium to WTI of $19.55 per barrel. The NYMEX RBOB forward price differential to WTI over the twelve months ending

 

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December 31, 2013, as of November 2, 2012, was $20.39 per barrel. Based on these assumptions, we forecast our net gasoline sales to be $3.8 billion for the twelve months ending December 31, 2013. For the year ended December 31, 2011, we sold approximately 31.7 million barrels of gasoline at a weighted average price of $118.66 per barrel and realized net gasoline revenues of approximately $3.8 billion. For the twelve months ended September 30, 2012, we sold approximately 34.5 million barrels of gasoline at a weighted average price of $116.63 per barrel and realized net gasoline revenues of approximately $4.0 billion.

Distillate. We estimate net distillate sales based on forecast future product prices multiplied by the number of barrels of distillate we estimate that we will produce and sell during the twelve months ending December 31, 2013. We forecast that we will produce and sell approximately 27.0 million barrels of distillate at a weighted average price of $130.22 per barrel during the twelve months ending December 31, 2013. We project the weighted average selling price of distillate based on projected estimates of WTI and the projected Group 3 distillate benchmark price differential to WTI. We assumed a weighted average distillate price premium to WTI of $35.18 per barrel. The NYMEX heating oil forward price differential to WTI over the twelve months ending December 31, 2013, as of November 2, 2012, was $34.31. Based on these assumptions, we forecast our net distillate sales to be $3.5 billion for the twelve months ending December 31, 2013. For the year ended December 31, 2011, we sold approximately 24.5 million barrels of distillate at a weighted average price of $127.66 per barrel and realized net distillate revenues of approximately $3.1 billion. For the twelve months ended September 30, 2012, we sold approximately 26.8 million barrels of distillate at a weighted average price of $128.39 per barrel and realized net distillate revenues of approximately $3.4 billion.

Other Products. In addition to gasoline and distillate, we produce and sell other refined products, including asphalt, propane, butane, propylene, sulfur, solvents and heavy oil and petroleum coke. We forecast that we will sell approximately 7.0 million barrels of these products at a weighted average price of $53.59 per barrel during the twelve months ending December 31, 2013. Based on these assumptions, we forecast net sales of other products to be approximately $377.3 million during the twelve months ending December 31, 2013. For the year ended December 31, 2011, we sold approximately 5.9 million barrels of other products at a weighted average price of $85.18 per barrel and realized net revenues of approximately $500.5 million. For the twelve months ended September 30, 2012, we sold approximately 5.3 million barrels of other products at a weighted average price of $102.38 per barrel and realized net revenues of approximately $542.4 million.

Cost of Sales

We estimate that our cost of sales for the twelve months ending December 31, 2013 will be approximately $6.5 billion. Pro forma for the Wynnewood acquisition, our cost of sales for the year ended December 31, 2011 and twelve months ended September 31, 2012 was approximately $6.1 billion and $6.5 billion, respectively.

Cost of sales includes the purchased raw material costs for crude oil and other feedstocks and blendstocks, and are driven primarily by commodity prices and volumes.

Crude Oil. We estimate that we will purchase approximately 62.8 million barrels of crude oil for the twelve months ending December 31, 2013. We estimate crude oil costs of approximately $5.8 billion and that our realized crude oil cost will be $93.01 per barrel for the twelve months ending December 31, 2013. We forecast that we will realize an average crude oil price discount of approximately $2.03 per barrel to the benchmark Cushing WTI price. Pro forma for the Wynnewood acquisition, for the year ended December 31, 2011 and twelve months ended September 31, 2012, our crude oil throughputs were approximately 59.3 million and 61.9 million barrels of crude oil, respectively, at an average cost per barrel of crude oil consumed of $92.71 per barrel and $92.87 per barrel, respectively, for total crude oil costs of approximately $5.5 billion and $5.8 billion, respectively.

Feedstocks and Blendstocks. Cost of sales also includes the cost of natural gasoline, isobutane, normal butane, and other feedstocks and blendstocks and other components, that we may blend into our gasoline and distillate finished products. We forecast these elements of cost of sales to be approximately $438.0 million over

 

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the twelve months ending December 31, 2013. The forecast reflects increased production due to reduced downtime associated with turnaround activities and more favorable NGL blending economics. For the year ended December 31, 2011 and the twelve months ended September 31, 2012, these elements of cost of sales were approximately $261.6 million and $224.4 million, respectively.

Direct Operating Expenses

Direct operating expenses include costs associated with the operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. We estimate that our direct operating expenses for the twelve months ending December 31, 2013 will be approximately $320.7 million, or $5.11 per barrel of crude throughput. Pro forma for the Wynnewood acquisition, our direct operating expenses, which exclude major turnaround expenses, for year ended December 31, 2011 and twelve months ended September 31, 2012 were $278.6 million and $290.9 million, respectively, or $4.70 and $4.70, respectively per crude throughput barrel. Our direct operating expenses are generally fixed, and increases in refinery utilization generally result in a lower direct operating cost per barrel.

Selling, General and Administrative Expenses

Selling, general and administrative expenses include salary and benefits costs for executive management, share-based compensation, accounting and information technology personnel, legal, audit, tax and other professional service costs. We estimate that our selling, general and administrative expenses for the twelve months ending December 31, 2013 will be approximately $80.2 million, including approximately $9.4 million of share-based compensation expense. Pro forma selling, general and administrative expenses for the year ended December 31, 2011 and the twelve months ended September 31, 2012 was approximately $72.7 million and $95.6 million, respectively.

The largest contributors to the forecasted increase in selling, general and administrative expenses are increased personnel expenses associated with the acquisition of the Wynnewood operations and the expected increased costs as a result of becoming a publicly traded partnership. These costs include increased allocations of personnel costs from CVR Energy under the Services Agreement to comply with public company reporting requirements. Other increased outside services included in selling, general and administrative expenses associated with becoming a publicly traded partnership include costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees.

Depreciation and Amortization

We estimate that depreciation and amortization for the twelve months ending December 31, 2013 will be approximately $115.6 million, as compared to $98.9 million and $106.6 million, respectively on a pro forma basis for the year ended December 31, 2011 and the twelve months ended September 30, 2012.

Interest Expense

Interest expense for the forecast period relates primarily to interest on our new senior unsecured notes as well as unused fees under our New ABL Credit Facility, interest related to capital lease obligations, interest under our new intercompany credit facility and amortization of deferred financing costs.

For the year ending December 31, 2013, we expect to incur approximately $39.7 million in interest expense, of which $32.5 million is cash interest expense associated with our new senior unsecured notes, approximately $1.2 million is non-cash interest expenses attributable to the amortization of deferred financing costs, approximately $1.5 million relates to unused line fees incurred under our New ABL Credit Facility, approximately $5.2 million relates to capital lease obligations and approximately $1.0 million is cash interest

 

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Index to Financial Statements

expense associated with the new intercompany credit facility. The above interest expense is partially reduced for capitalized interest of approximately $1.7 million. We do not expect to have significant borrowings under our New ABL Credit Facility and we plan to borrow approximately $47.5 million on the new intercompany credit facility to finance growth capital spend during the year ending December 31, 2013.

Capital Expenditures

We estimate total capital expenditures during the year ending December 31, 2013 of approximately $231.7 million, of which approximately $89.5 million is maintenance capital expenditures, $94.7 million is environmental capital expenditures and $47.5 million is growth capital expenditures. Pro forma capital expenditures for the year ended December 31, 2011 and the twelve months ended September 30, 2012 were approximately $87.6 million and $122.8 million, respectively, of which approximately $69.4 million and $97.7 million, respectively, was maintenance capital expenditures and $18.2 million and $25.1 million, respectively, was growth capital expenditures.

Maintenance capital expenditures represent the costs of required maintenance projects on the processing units of our refineries and other assets but exclude the costs related to major turnarounds of our refineries. Environmental capital expenditures represent costs required to comply with environmental requirements and legislations.

Growth capital expenditures represent costs of projects to improve the profitability of our refineries and related infrastructure. We expect to fund growth capital expenditures for the year ending December 31, 2013 with borrowings under our new intercompany credit facility with Coffeyville Resources and therefore the cash available for distribution for the year ending December 31, 2013 will not be impacted by these planned expenditures.

Scheduled Turnaround Reserve

We project that major turnarounds at our refineries will occur once every four years with an estimated total cost per turnaround for both refineries of approximately $140.0 million. The next major scheduled turnaround for our Coffeyville Refinery is expected to begin in the fourth quarter of 2015 and the next major scheduled turnaround for our Wynnewood refinery is expected to begin in the fourth quarter of 2016.

The board of directors of our general partner intends to reserve amounts to fund the expenses associated with planned turnarounds of our refineries. Such action may have an adverse impact on our cash available for distribution in the quarters in which the reserves are increased and a corresponding mitigating impact on the future quarters in which the reserves are utilized. We estimate reserving approximately $35.0 million of cash per year for scheduled turnaround expenses.

Environmental and Maintenance Capital Expenditures and Related Reserve

The board of directors of our general partner intends to reserve amounts to fund future environmental and maintenance capital expenditures. Such action may have an adverse impact on our cash available for distribution in the quarters in which the reserves are increased and a corresponding mitigating impact on the future quarters in which the reserves are utilized. We estimate reserving approximately $125.0 million of cash per year for environmental and maintenance capital expenditures.

In order to fund the expected environmental and maintenance capital expenditures for the year ending December 31, 2013, $160.0 million of proceeds from this offering and related transactions will be reserved.

Regulatory, Industry and Economic Factors

Our forecast for the year ending December 31, 2013, is based on the following assumptions related to regulatory, industry and economic factors: