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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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:

 

   

no material nonperformance or credit-related defaults by suppliers, customer or vendors;

 

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no new regulation or interpretation of existing regulations that, in either case, would be materially adverse to our business;

 

   

no material accidents, weather-related incidents, floods, unplanned turnarounds or other downtime or similar unanticipated events that would reduce our capacity utilization below what we are currently forecasting;

 

   

no material adverse change in the market in which we operate resulting from reduced demand for our products;

 

   

no material decreases in the prices we receive for our products; and

 

   

no material changes to market or overall economic conditions.

Actual conditions may differ materially from those anticipated in this section as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Compliance with Debt Covenants

Our ability to make distributions could be affected if we do not remain in compliance with the covenants in our indenture, New ABL Credit Facility and new intercompany credit facility. We have assumed we will remain in compliance with such covenants.

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. Based upon our forecast fixed charge coverage ratio of 23.1 to 1, we do not expect the covenants contained in the senior notes will limit our ability to pay distributions during the year ending December 31, 2013.

The New ABL Credit Facility contains certain restrictive covenants that may limit our ability to pay cash distributions. In particular, the New ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeding 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00.

Sensitivity Analysis

Our cash available for distribution is significantly impacted by volatility in prevailing crack spreads, crude oil prices and throughput at our refineries. In the paragraphs below, we discuss the impact of changes in these variables, while holding all other variables constant, on our ability to generate our estimated cash available for distribution for the year ending December 31, 2013.

Crack Spread Volatility and Crude Price Impact

Crack spreads measure the difference between the price received from the sale of gasoline and distillates and the price paid for crude oil. Holding all other variables constant, we expect that a $1.00 per barrel increase (decrease) in the NYMEX 2:1:1 crack spread would increase (decrease) our cash available for distribution by

 

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$60.2 million for the year ending December 31, 2013. The impact of a $1.00 per barrel increase (decrease) in the NYMEX 2:1:1 crack spread on our derivative contracts would be a $22.7 million decrease (increase) in our cash available for distribution for the year ending December 31, 2013.

Our refineries experience a loss of volume of crude oil during the refining process. On average for the two refineries we have assumed an approximate 5% loss of crude oil through the normal processing to refined products. Assuming a crude oil price of $100 per barrel, there would be an approximate $5.00 loss per crude oil throughput barrel with an average and assumed 5% liquid volume loss. The impact of a $1.00 per barrel increase (decrease) in our realized cost of crude on our loss on volume would be a $3.14 million decrease (increase) in our cash available for distribution for the year ending December 31, 2013.

The NYMEX 2:1:1 crack spread and WTI price are highly volatile and may change materially over a short period of time. We caution you not to place undue reliance on prices as of any given date or the magnitude or direction of short-term changes in the NYMEX 2:1:1 crack spread or WTI price, including the changes described in the above table.

Crude Oil Differential

We are exposed to significant fluctuations in the realized crude oil to WTI price differential. Holding all other variables constant, we expect a $1.00 per barrel increase (decrease) in the realized crude oil to WTI price differential would increase (decrease) our cash available for distribution by approximately $67.8 million for the year ending December 31, 2013.

Refinery Throughput

Holding all other variables constant, we expect a 1,000 bpd increase (decrease) in our total crude oil throughput would increase (decrease) our cash available for distribution by $6.9 million for the twelve months ending December 31, 2013.

 

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HOW WE MAKE CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

General

Within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2013, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

Method of Distributions

We will distribute available cash to our unitholders, pro rata; provided, however, that our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank. Our partnership agreement permits us to borrow to make distributions, but we are not required and do not intend to borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

We do not have a legal obligation to pay distributions, and the amount of distributions paid under our policy and the decision to make any distribution is determined by the board of directors of our general partner. Moreover, we may be restricted from paying distributions of available cash by the instruments governing our indebtedness. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

General Partner Interest

Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future and will be entitled to receive pro rata distributions therefrom.

 

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SELECTED 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, LLC, 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 selected unaudited pro forma combined financial and operating data of CVR Refining, LP as of the dates and for the periods indicated.

The selected combined financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2009, 2010 and 2011 and the selected combined financial information presented below under the caption Balance Sheet Data as of December 31, 2010 and 2011, have been derived from our audited combined financial statements included elsewhere in this prospectus, which combined financial statements have been audited by KPMG LLP, an independent registered public accounting firm. The selected combined financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2007 and 2008 and the selected combined financial information presented below under the caption Balance Sheet Data as of December 31, 2007, 2008 and 2009 have been derived from our unaudited combined financial statements that are not included in this prospectus. The selected combined financial information presented below under the caption Statement of Operations Data for the nine months ended September 30, 2011 and 2012 and the selected 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, 2008, 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 in “Prospectus Summary—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 statements 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 GAAP. The unaudited pro forma combined financial data presented below has been derived from the “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.

 

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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 combined net income per unit is determined by dividing the pro forma combined 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 combined 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 our audited and unaudited historical combined financial statements 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,     Nine Months
Ended
September  30,
         Year
Ended
December  31,
  2011  
    Nine Months
Ended
September 30,
  2012  
 
      2007         2008         2009         2010         2011(1)         2011         2012             
    (unaudited)                       (unaudited)          (unaudited)  
    (in millions, except per unit data and as otherwise indicated)  

Statement of Operations Data:

                     

Net sales

  $ 2,806.2      $ 4,774.3      $ 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)

    2,300.2        4,449.4        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)

    248.6        159.2        142.2        153.1        247.7        144.0        253.1            345.0        253.1   

Selling, general and administrative expenses(2)

    71.9        27.6        40.0        43.1        51.0        31.4        67.5            72.7        67.5   

Depreciation and amortization

    43.0        62.7        64.4        66.4        69.8        50.9        80.4            98.9        80.4   

Goodwill impairment(3)

    —          42.8        —          —          —          —          —              —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Operating income

  $ 142.5      $ 32.6      $ 174.0      $ 103.2      $ 456.7        468.5      $ 873.5          $ 755.7      $ 873.5   

Other income (expense), net(4)

    0.1        (8.9     (0.3     (13.8     (1.5     (1.2     0.6            (1.4     0.6   

Interest expense and other finance costs

    (36.9     (38.7     (43.8     (49.7     (53.0     (39.2     (56.0         (41.7     (31.6

Realized gain (loss) on derivatives, net

    (169.9     (122.6     (27.5     (2.1     (7.2     (18.3     (80.4         (49.0     (80.4

Unrealized gain (loss) on derivatives, net

    (111.6     247.9        (37.8     0.6        85.3        (6.8     (197.0         85.4        (197.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Net income (loss)(4)

  $ (175.8   $ 110.4      $ 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

  $ 3.4      $ 0.6      $ 2.7      $ 2.3      $ 2.7      $ —        $ 79.5          $ 340.0      $ 340.0   

Working capital

    (94.6     64.7        173.7        138.7        384.7        160.5        336.4            734.9        625.7   

Total assets

    1,302.0        1,079.0        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

    489.2        484.3        479.5        469.0        729.9        466.7        727.0            553.2        552.5   

Total divisional equity/partners’ capital

    226.9        405.6        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(5)

        3.8        (146.3     303.6        (393.7     (640.0        
 

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(6)

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

 

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    CVR Refining, LP Historical Combined          CVR Refining, LP Combined
Pro Forma
 
    Year Ended December 31,     Nine Months Ended
September 30,
   

 

  Year
Ended
December  31,
  2011  
    Nine Months
Ended
September 30,
  2012  
 
      2007         2008         2009         2010         2011(1)         2011         2012             
    (unaudited)                       (unaudited)         (unaudited)  
    (in millions, except per unit data and as otherwise indicated)  
 

Key Operating Data:

                     

Crude oil throughput(bpd)(7):

                     

Sweet

    54,509        77,315        82,598        89,746        83,538        85,401        136,463            132,638        136,463   

Medium

    14,580        16,795        15,602        8,180        1,704        598        21,708            11,338        21,708   

Heavy sour

    7,228        11,727        10,026        15,439        18,460        21,071        18,418            18,460        18,418   

All other feedstocks and blendstocks

    5,748        11,882        12,013        10,350        5,231        5,671        9,448            8,466        9,448   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

   

 

 

 

Total throughput (bpd)(7)

    82,065        117,719        120,239        123,715        108,933        112,741        186,037            170,902        186,037   

Production (bpd):

                     

Gasoline

    37,017        56,852        62,039        61,136        48,486        50,998        92,114            80,704        92,114   

Distillate

    34,814        48,257        46,909        50,439        45,535        47,368        75,568            65,321        75,568   

Other

    10,551        13,422        11,549        12,978        15,385        15,038        17,588            22,895        17,588   

Total refining production (excluding internally produced fuel)

    82,382        118,531        120,767        124,553        109,406        113,404        185,270            168,920        185,270   

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

  $ 13.95      $ 12.50      $ 8.54      $ 10.07      $ 26.33      $ 27.27        29.87          $ 26.33      $ 29.87   

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

    19.71        14.68        7.93        10.01        26.77        27.82        29.60            26.77        29.60   

Refining margin per crude oil throughput barrel(6)

      $ 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(6)

      $ 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(6)

      $ 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(6)

      $ 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 selected 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) Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that our goodwill was impaired, which resulted in a goodwill impairment loss of $42.8 million. This represented a write-off of the entire balance of the goodwill.

 

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(4) The following are certain charges and costs incurred in the years ended December 31, 2009, 2010 and 2011 and the nine months ended September 30, 2011 and 2012 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:

 

    CVR Refining, LP
Historical Combined
         CVR Refining, LP Combined
Pro Forma
 
    Year Ended
December 31,
    Nine Months Ended
September 30,
         Year Ended
December 31,
  2011  
    Nine Months
Ended
September 30,
  2012  
 
      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 expenses

    —          —          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 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 a major scheduled turnaround at our refineries.
  (d) Represents the impact of share-based compensation awards.

 

(5) 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.
(6) Please see “—Non-GAAP Financial Measures” below for reconciliations to the most directly comparable GAAP financial measure.
(7) 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 facility’s continuous operations.
(8) Data published by Platts and Oil Price Information Service and represents average pricing for the periods presented.

 

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

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   

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   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

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

 

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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 expenses, 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,

  2011  
    Nine Months
Ended
September 30,

  2012  
 
      2009         2010         2011         2011          2012             
    ($ in millions)  
   

(unaudited)

 

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   

Income tax expense

    —          —          —          —           —              —          —     

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 expense

    —          —          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   
 

 

 

   

 

 

   

 

 

   

 

 

    

 

 

       

 

 

   

 

 

 

 

(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.

 

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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 major 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 expense and adjusted for FIFO impact

    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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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition, results of operations and cash flows in conjunction with our combined financial statements and related notes included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this prospectus.

The following discussion of our historical performance and financial condition is based on the historical combined financial statements, which represents the historical operations of the refining and logistics operating subsidiaries of our sponsor, CVR Energy. These subsidiaries were contributed to us on December 31, 2012. You should read the following discussion of the historical financial condition and results of operations in conjunction with our historical combined financial statements and our pro forma combined financial statements included elsewhere in this prospectus.

Overview of our Business

We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the underserved Group 3 of the PADD II region of the United States. Our business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd medium complexity crude oil refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Oklahoma, western Missouri, southwestern Nebraska and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and located at throughput terminals on Magellan and NuStar refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of owned pipeline) that transports crude oil to our Coffeyville refinery from our Broome Station tank farm located near Caney, Kansas and (4) over 6.0 million barrels of crude oil storage.

Our Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Our Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. The early June 2012 reversal of the Seaway Pipeline that now flows from Cushing to the U. S. Gulf Coast has eliminated our ability to source foreign waterborne crude oil, as well as deepwater U.S. Gulf of Mexico produced sweet and sour crude oil grades. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P., and NuStar.

Crude oil is supplied to our Coffeyville refinery through our gathering system and by a pipeline owned by Plains Pipeline, L.P. that runs from Cushing to our Broome Station tank farm. We maintain capacity on the Spearhead and Keystone pipelines from Canada to Cushing. We also maintain leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Our Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades, various Canadian medium and heavy sours and sweet synthetics. Crude oil is supplied to our Wynnewood refinery through two third-party pipelines operated by Sunoco Pipeline and Excel Pipeline and historically has mainly been sourced from Texas and Oklahoma. Our Wynnewood refinery is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and other U.S. domestically produced crude oils. The access to a variety

 

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of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the third quarter of 2012 was $4.38 per barrel compared to $2.57 per barrel in the third quarter of 2011.

Transaction Agreement

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the “Transaction Agreement”) with certain affiliates of Icahn Enterprises and Carl C. Icahn. Pursuant to the Transaction Agreement, a wholly-owned subsidiary of Icahn Enterprises offered (the “Offer”) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment (“CCP”) right for each share which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes.

In May 2012, affiliates of Icahn Enterprises acquired a majority of the common stock of CVR Energy through the Offer. As a result of shares tendered into the Offer during the initial offering period, the subsequent offering period and subsequent additional purchases, Icahn Enterprises owned approximately 82% of the outstanding common stock of CVR Energy as of September 30, 2012.

Pursuant to the Transaction Agreement, for a period of 60 days CVR Energy solicited proposals or offers from third parties to acquire CVR Energy. The 60 day period began on May 24, 2012 and ended on July 23, 2012 without any qualifying offers.

Pursuant to the Transaction Agreement, all employee restricted stock awards (“awards”) that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

Agreements with Affiliates

In connection with the initial public offering of CVR Energy and the transfer of the nitrogen fertilizer business to CVR Partners in October 2007, CVR Energy entered into a number of agreements with CVR Partners and its affiliates that govern the business relations among CVR Partners, CVR Energy and its affiliates, and the general partner of CVR Partners. In connection with CVR Partners’ initial public offering, CVR Energy amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Partners. These include (i) the pet coke supply agreement under which CVR Partners purchases the pet coke we generate at our Coffeyville refinery for use in CVR Partners’ manufacture of nitrogen fertilizer; (ii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iii) a raw water and facilities sharing agreement, which allocates raw water resources between the Coffeyville refinery and the nitrogen fertilizer plant; (iv) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners; (v) a cross-easement agreement, which grants easements to both parties for operational facilities, pipelines, equipment, access, and water rights; and (vi) an environmental agreement which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville refinery and the nitrogen fertilizer plant.

These agreements were not the result of arm’s-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties. For more information, see “Certain Relationships and Related Party Transactions.”

 

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Crude Oil Supply Agreement

In August 2012, we and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between us and Vitol dated March 30, 2011, as amended. The March 2011 agreement replaced the previous supply agreement between us and Vitol dated December 2, 2008, as amended, which was terminated by Vitol and us on March 30, 2011.

The Vitol Agreement provides that we will obtain substantially all of the crude oil for our Coffeyville and Wynnewood refineries through Vitol, other than the crude oil gathered by us. We and Vitol will work together to identify crude oil and pricing terms that meet our crude oil requirements. We and/or Vitol will negotiate the costs of each barrel of crude oil that is purchased from third-party crude oil suppliers. Vitol purchases all such crude oil, executes all third-party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to us. Title and risk of loss for all crude oil purchased by us through the Vitol Agreement passes to us upon delivery to one of three delivery points described in the Vitol Agreement. We pay Vitol a fixed origination fee per barrel plus the negotiated cost (including logistics costs) of each barrel purchased.

The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014. Following the initial term, the Vitol Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the initial term or any renewal term. Notwithstanding the foregoing, we have an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

Factors Affecting Comparability

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

Wynnewood Acquisition

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 and referred to herein as “WEC”) for $593.4 million, consisting of an initial cash payment of $525.0 million, capital expenditure adjustments of $1.8 million and $66.6 million for working capital (the “Wynnewood Acquisition”). The assets acquired include the 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of storage tanks.

The financial results of WEC have been included in our results of business since the date of the Wynnewood Acquisition. Results for the year ended December 31, 2011 included net sales of approximately $115.7 million and a net loss of $2.3 million related to WEC for the period from December 16, 2011 through December 31, 2011. For the nine months ended September 30, 2012, our results included net sales of approximately $2,380.6 million and operating income of $319.1 million related to WEC. Future periods’ results of operations will include full periods of WEC’s financial results.

Indebtedness

ABL Credit Facility. On February 22, 2011, Coffeyville Resources and certain of its subsidiaries entered into a $250.0 million asset-backed revolving credit agreement (the “ABL credit facility”). The ABL credit facility replaced the first priority credit facility described below, which was terminated. As a result of the termination of the first priority credit facility, a portion of the previously deferred financing costs of

 

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approximately $1.9 million were written off. This expense is reflected on the Combined Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2011. On December 15, 2011, Coffeyville Resources entered into an incremental commitment agreement to increase availability under the ABL credit facility by an additional $150.0 million. In connection with entering into and then expanding the ABL credit facility, approximately $9.9 million of fees were incurred that were deferred and are to be amortized over the term of the credit facility on a straight-line basis. As the ABL credit facility is maintained for the benefit of our operations, all fees and borrowings under the facility have been allocated to us in our historical combined financial statements. On December 20, 2012, we amended and restated the ABL credit facility. Please see “—Liquidity and Capital Resources—Borrowing Activities—New ABL Credit Facility.”

Notes. In April 2010, Coffeyville Resources and its wholly-owned subsidiary, Coffeyville Finance Inc. issued $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The proceeds from the sale of the Notes were used to pay off $453.0 million of term loans as described below under “—First Priority Credit Facility.” As the Notes were incurred for the benefit of our operations, all debt and associated costs have been allocated to us in our historical combined financial statements.

In December 2010, Coffeyville Resources made a voluntary unscheduled payment of $27.5 million on the First Lien 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 approximately $1.6 million, which was recognized as a loss on extinguishment of debt in the Combined Statements of Operations.

On December 15, 2011, Coffeyville Resources and Coffeyville Finance issued an additional $200.0 million of First Lien Notes to partially fund the Wynnewood Acquisition. Financing and other third party costs incurred at the time of $6.0 million were deferred and are amortized over the remaining term of the First Lien Notes. In connection with the Wynnewood Acquisition, in November 2011 Coffeyville Resources received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of the First Lien Notes. Fees and other third party costs related to the bridge commitment totaling $3.9 million were expensed in December 2011. Coffeyville Resources also recognized approximately $0.1 million of third party costs at the time the First Lien Notes were issued. Other financing and third party costs incurred at the time were deferred and are amortized over the respective terms of the First Lien Notes. The premiums paid, previously deferred financing costs subject to write-off and immediately recognized third party expenses are reflected as a loss on extinguishment of debt in the Combined Statements of Operations.

On October 23, 2012, CVR Refining, LLC and Coffeyville Finance issued $500 million aggregate principal amount of 6.5% senior notes due 2022 (the “New Notes”). 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 First Lien Notes. Financing and other third party costs incurred in connection with the issuance of the New Notes will be deferred and amortized over the remaining term of the New Notes. As a result of the repurchase of the First Lien Notes, a portion of the previously deferred financing costs related to the First Lien Notes will be written off.

In addition, we expect that a portion of the net proceeds of this offering, after deducting underwriting discounts, offering expenses and structuring fees payable by us, will be used repurchase all or a portion of the Second Lien Notes.

First Priority Credit Facility. In December 2006, Coffeyville Resources entered into a credit facility (the “First Priority Credit Facility”) consisting of $775.0 million of tranche D term loans (the “tranche D term loans”) a $150.0 million revolving credit facility and a $150.0 million first priority funded letter of credit in support of a cash flow swap. The First Priority Credit Facility was repaid in full in connection with the issuance of the Notes

 

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in April 2010. As the First Priority Credit Facility was maintained for our benefit, the historical fees and debt associated with the facility have been allocated to us in our historical combined financial statements.

In June 2009, Coffeyville Resources successfully reduced the first priority funded letter of credit issued under our First Priority Credit Facility from $150.0 million to $60.0 million. On October 2, 2009, Coffeyville Resources entered into the third amendment to the First Priority Credit Facility, after which it terminated the cash flow swap on October 8, 2009 in advance of its original expiration of June 30, 2010. As a result of the reduction of the first priority funded letter of credit and eventual termination of the remaining $60.0 million first priority funded letter of credit facility on October 15, 2009, previously deferred financing costs totaling approximately $2.1 million were written off. This amount is reflected on the Combined Statements of Operations as a loss on extinguishment of debt.

In connection with the third amendment to the First Priority Credit Facility, Coffeyville Resources incurred lender fees of approximately $2.6 million. These fees were recorded as deferred financing costs in the fourth quarter of 2009. In addition, Coffeyville Resources incurred third party costs of approximately $1.4 million, primarily consisting of administrative and legal costs. Of the third party costs incurred, approximately $0.9 million were expensed in 2009. The remaining $0.5 million was recorded as additional deferred financing costs.

In January 2010, Coffeyville Resources made a voluntary unscheduled principal payment of $20.0 million on its tranche D term loans. In addition, it made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing the tranche D term loans’ outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, a 2.0% premium totaling $0.5 million was paid to the lenders of the First Priority Credit Facility. The proceeds from the issuance of the Notes in April 2010 were used to pay off the remaining $453.0 million term loans.

In March 2010, Coffeyville Resources entered into a fourth amendment to the First Priority Credit Facility. In connection with the fourth amendment, it incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, Coffeyville Resources incurred third party costs of approximately $1.5 million, primarily consisting of administrative and legal costs. Of the third party costs incurred approximately $1.1 million were expensed in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs.

In April 2010, upon issuance of the Notes and repayment of the First Priority Credit Facility, previously deferred financing costs totaling approximately $5.4 million associated with the First Priority Credit Facility term debt were written off. In connection with the payoff, Coffeyville Resources paid a 2.0% premium totaling approximately $9.1 million.

Cash Flow Swap

Until October 8, 2009, Coffeyville Resources and a related party were parties to a cash flow swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. On October 8, 2009, the cash flow swap was terminated and all remaining obligations were settled in advance. Coffeyville Resources determined that the cash flow swap did not qualify as a hedge for hedge accounting treatment under FASB ASC Topic 815, Derivatives and Hedging. As a result, the Combined Statements of Operations reflects all the realized and unrealized gains and losses from this swap which created significant fluctuations in our results of operations between periods. As a result of the termination of the cash flow swap in the fourth quarter of 2009, there was no impact to the Combined Statements of Operations for the years ended December 31, 2011 and 2010. For the year ended December 31, 2009, a net realized loss of $14.3 million was recorded with respect to the cash flow swap. In addition, for the year ended December 31, 2009, a net unrealized loss of $40.9 million was recorded.

 

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Share-Based Compensation

Certain of our employees and employees of CVR Energy who perform services for us participate in equity compensation plans of CVR Energy and its affiliates. Accordingly, we have been allocated and have recorded share-based compensation expense related to these plans. Through CVR Energy’s Long-Term Incentive Plan (the “CVR Energy LTIP”), equity compensation awards may be awarded to CVR Energy’s employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by affiliates of Icahn Enterprises and the related change of control described above, restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the years ended December 31, 2011, 2010 and 2009, we were allocated compensation expense of $3.3 million, $0.5 million and $0.1 million, respectively, related to non-vested share-based compensation awards issued through the CVR Energy LTIP.

The change of control and related Transaction Agreement triggered a modification to the CVR Energy LTIP. Pursuant to the Transaction Agreement, all employee restricted stock awards that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, additional share-based compensation was incurred to revalue the unvested shares to the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. In addition, the classification changed from an equity award to a liability award due to the cash settlement of the awards. For the nine months ended September 30, 2012 and 2011, we were allocated compensation expense of $15.6 million and $8.0 million, respectively, related to non-vested share-based compensation awards issued through the CVR Energy LTIP.

Coffeyville Resources had two Phantom Unit Appreciation Plans, (the “Phantom Unit Plans”), whereby directors, employees, and service providers historically could be awarded phantom points at the discretion of the board of directors of CVR Energy or the compensation committee. The Phantom Unit Plans provided for two classes of interests: phantom service points and phantom performance points (collectively referred to as “phantom points”). The phantom points represented a contractual right to receive a payment when payment was made in respect of certain profits interests in our former sponsors, as applicable. Coffeyville Resources accounted for awards under the Phantom Unit Plans as liability based awards. In accordance with FASB ASC Topic 718, Compensation—Stock Compensation, the expense associated with these awards was based on the current fair value of the awards which was derived from a probability-weighted expected return method.

For the years ended December 31, 2011, 2010 and 2009, we were allocated compensation expense of $5.6 million, $11.0 million and $2.4 million, respectively, as a result of the phantom and certain override unit share-based compensation awards issued in connection with CVR Energy’s initial public offering. Due to the divestiture of all ownership of CVR Energy by its former sponsors in 2011, there will be no further share-based compensation expense associated with override units subsequent to 2011. For the nine months ended September 30, 2011, we were allocated $5.6 million related to the phantom and override units. In association with the divestiture of ownership and the distributions to the override unitholders of such sponsors, the holders of phantom units received the associated payments in 2011. As a result, there will be no further share-based compensation expense recorded for the Phantom Unit Plans subsequent to 2011.

Commodity Swaps

Beginning in September 2011, Coffeyville Resources entered into commodity swap contracts on our behalf with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected in our Combined Balance

 

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Sheets with changes in fair value currently recognized in our Combined Statement of Operations. At September 30, 2012, there were open commodity hedging instruments consisting of 26.3 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production with effective periods beginning in 2012 and 2013. None of these swap contracts were designated as cash flow hedges and all changes in fair market value will be reported in earnings in the period in which the value change occurs.

Turnaround Projects

Turnaround projects are a required standard procedure that involves the shut down and inspection of major process units in order to refurbish, repair and maintain the plant assets. These major maintenance projects occur every four to five years for our refineries.

The Coffeyville refinery completed the second phase of a two-phase scheduled turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery incurred costs of approximately $21.2 million and $12.2 million for the nine months ended September 30, 2012 and 2011, respectively, associated with the 2011/2012 turnaround. Costs associated with turnaround projects are recorded in direct operating expense (exclusive of depreciation and amortization) on the Combined Statements of Operations.

The Wynnewood refinery began turnaround maintenance in the fourth quarter of 2012. We incurred approximately $105.0 million of expenses during 2012 related to the Wynnewood refinery’s turnaround, which was completed in December 2012. The downtime associated with this turnaround significantly impacted our results of operations for the fourth quarter of 2012. The Wynnewood refinery incurred $13.4 million of turnaround costs in the nine months ended September 30, 2012.

Publicly Traded Partnership Expenses

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

Results of Operations

The period to period comparisons of our results of operations have been prepared using the historical periods included in our combined financial statements. These financial statements reflect the historical operations of the petroleum refining and related logistics business of CVR Energy. This “Results of Operations” section compares the nine months ended September 30, 2012 with the nine months ended September 30, 2011, as well as the year ended December 31, 2011 with the year ended December 31, 2010 and the year ended December 31, 2010 with the year ended December 31, 2009.

Factors Affecting Our Results of Operations

Crude Oil, Other Feedstock and Refined Product Prices. Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks, including natural gas liquids, that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies,

 

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weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out (“FIFO”) accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

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

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

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

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces, resulting in prices that reflect the logistics cost for Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refineries is that prices we realize are different than those used in determining the 2-1-1

 

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crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

Direct Operating Expenses. Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the nine months ended September 30, 2012, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $5.8 million.

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

Scheduled and Unscheduled Downtime. Safe and reliable operations at our refineries are key to our financial performance and results of operations. Unscheduled downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. Our Coffeyville refinery completed the first phase of a two-phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012, and its next turnaround is scheduled to begin in late 2015. We completed a turnaround at our Wynnewood refinery in December 2012. The next turnaround for the Wynnewood refinery is scheduled to begin in late 2016.

Our Coffeyville refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (the “FCCU”) on December 28, 2010, which led to reduced crude oil throughput and repair costs of approximately $2.2 million net of an insurance receivable for the year ended 2011. We used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4.0 million in total. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted our production of refined products in the first quarter of 2011. We estimate that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident.

Our Coffeyville refinery also experienced a small fire at its continuous catalyst reformer (the “CCR”) in May 2011, which led to reduced crude oil throughput for the second quarter of 2011. Repair costs, net of the insurance receivable, recorded for the year ended December 31, 2011 were approximately $2.5 million. The interruption adversely impacted the production of refined products for the second quarter of 2011.

Our Wynnewood refinery experienced an unplanned maintenance event upon turnover of the facility to CVR Energy. Operating deficiencies associated with the fluidized catalytic cracking unit required a 27-day outage to repair damage to the unit at a cost of $1.7 million. The outage required cutting our crude rate during the period.

 

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Results of Operations

The following discussion of our results of operations is based on the historical operations of the petroleum refining and related logistics business of CVR Energy, including the operations of both the Coffeyville and Wynnewood refineries, each of which was contributed to us on December 31, 2012. For the year ended December 31, 2011, the Wynnewood results are included for the post acquisition period of December 16, 2011 through December 31, 2011.

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

Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See “—Factors Affecting Our Results of Operations.” We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold.

 

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Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that management believes is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of product sold (exclusive of depreciation and amortization) that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold exclusive of depreciation and amortization) can be derived directly from our combined Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table shows selected combined information about our business, including refining margin:

 

    Year Ended
December 31,
    Nine Months Ended
September 30,
 
    2009     2010     2011     2011     2012  
   

($ in millions, except as otherwise indicated)

 
                      (unaudited)  

Statements of Operations Data:

         

Net Sales

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

Cost of product sold(1)

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

Direct operating expenses(1)(2)

    142.2        151.9        181.3        131.8        218.5   

Major scheduled turnaround expenses

    —          1.2        66.4        12.2        34.6   

Depreciation and amortization

    64.4        66.4        69.8        50.9        80.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross Profit(3)

  $ 214.0      $ 146.3      $ 507.7      $ 499.9      $ 941.0   

Plus:

         

Direct operating expenses and major scheduled turnaround expenses(1)

    142.2        153.1        247.7        144.0        253.1   

Depreciation and amortization

    64.4        66.4        69.8        50.9        80.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Refining margin(4)

  $ 420.6      $ 365.8      $ 825.2      $ 694.8      $ 1,274.5   

Operating income

  $ 174.0      $ 103.2      $ 456.7      $ 468.5      $ 873.5   

Adjusted EBITDA(5)

  $ 147.3      $ 152.6      $ 577.3      $ 525.0      $ 988.9   

Key Operating Statistics:

         

Per crude oil throughput barrel:

         

Refining margin(4)

  $ 10.65      $ 8.84      $ 21.80      $ 23.77      $ 26.34   

Refining margin adjusted for FIFO impacts(7)

    8.93        8.07        21.12        23.82        27.46   

Gross profit

    5.42        3.54        13.41        17.10        19.45   

Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact)(8)

    3.70        2.80        14.49        17.57        21.29   

Direct operating expenses(1)(2)

    3.60        3.70        6.54        4.93        5.23   

Direct operating expenses (excluding major scheduled turnaround expenses)(9)

    3.60        3.67        4.79        4.51        4.52   

Direct operating expenses per barrel sold(6)

    3.22        3.30        6.38        4.71        4.75   

Barrels sold (barrels per day)

    125,005        127,142        106,397        111,939        194,638   

 

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     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012  

Refining Throughput and Production Data(bpd):

          

Throughput:

          

Sweet

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

Medium

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

Heavy sour

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

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total crude oil throughput

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

Feedstocks and blendstocks

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

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total throughput

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

Production:

          

Gasoline

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

Distillate

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

Other (excluding internally-produced fuel)

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

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total refining production (excluding internally-produced fuel)

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

Utilization(10)

     94.1     98.6     87.8     95.5     93.1

Average sales price (dollars per gallon):

          

Gasoline

   $ 1.68      $ 2.10      $ 2.82      $ 2.89      $ 2.93   

Distillate

   $ 1.68      $ 2.20      $ 3.03      $ 3.04      $ 3.07   

Market Indicators (dollars per barrel):

          

West Texas Intermediate (WTI) NYMEX

   $ 62.09      $ 79.61      $ 95.11      $ 95.47      $ 96.16   

Crude Oil Differentials:

          

WTI less WTS (light/medium sour)

   $ 1.53      $ 2.15      $ 2.06      $ 2.46      $ 4.10   

WTI less WCS (heavy sour)

   $ 9.57      $ 15.07      $ 16.54      $ 17.86      $ 21.06   

NYMEX Crack Spreads:

          

Gasoline

   $ 9.05      $ 9.62      $ 23.54      $ 26.04      $ 29.21   

Heating Oil

   $ 8.03      $ 10.53      $ 29.12      $ 28.51      $ 30.54   

NYMEX 2-1-1 Crack Spread

   $ 8.54      $ 10.07      $ 26.33      $ 27.27      $ 29.87   

PADD II Group 3 Product Basis(11):

          

Gasoline

   $ (1.25   $ (1.49   $ (1.09   $ (1.21   $ (2.58

Ultra-Low Sulfur Diesel

   $ 0.03      $ 1.35      $ 1.98      $ 2.32      $ 2.04   

PADD II Group 3 Product Crack Spread(11):

          

Gasoline

   $ 7.81      $ 8.13      $ 22.44      $ 24.82      $ 26.63   

Ultra-Low Sulfur Diesel

   $ 8.06      $ 11.88      $ 31.10      $ 30.82      $ 32.58   

PADD II Group 3 2-1-1

   $ 7.93      $ 10.01      $ 26.77      $ 27.82      $ 29.60   

 

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     Nine Months Ended
September 30,
 
     2011      2012  
     ($ in millions, except as
otherwise indicated)
 
     (unaudited)  

Coffeyville Refinery Statements of Operations Data:

     

Net sales

   $ 3,772.1       $ 4,084.3   

Cost of product sold(1)

     3,077.7         3,268.2   

Direct operating expenses(1)(2)

     131.7         134.7   

Major scheduled turnaround expense

     12.2         21.2   

Depreciation and amortization

     49.0         52.1   
  

 

 

    

 

 

 

Gross Profit(3)

   $ 501.5       $ 608.1   

Plus:

     

Direct operating expenses and major scheduled turnaround expenses(1)

     143.9         155.9   

Depreciation and amortization

     49.0         52.1   
  

 

 

    

 

 

 

Refining margin

   $ 694.4       $ 816.1   

Operating income

   $ 471.5       $ 573.3   

Coffeyville Refinery Key Operating Statistics:

     

Per crude oil throughput barrel:

     

Refining margin(4)

   $ 23.76       $ 26.71   

Refining margin adjusted for FIFO impacts(7)

     23.81         28.08   

Gross profit

     17.16         19.90   

Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact)(8)

     17.62         21.96   

Direct operating expenses(1)(2)

     4.92         5.10   

Direct operating expenses (excluding major scheduled turnaround expenses)(9)

     4.51         4.41   

Direct operating expenses per barrel sold(6)

     4.71         4.65   

Barrels sold (barrels per day)

     111,939         122,482   

 

     Nine Months Ended
September 30,
 
     2011      2012  

Coffeyville Refinery Throughput and Production Data(bpd):

     

Throughput:

     

Sweet

     85,401         90,871   

Medium

     598         2,216   

Heavy sour

     21,071         18,418   
  

 

 

    

 

 

 

Total crude oil throughput

     107,070         111,505   

Feedstocks and blendstocks

     5,671         6,448   
  

 

 

    

 

 

 

Total throughput

     112,741         117,953   

Production:

     

Gasoline

     50,998         58,889   

Distillate

     47,368         50,766   

Other (excluding internally-produced fuel)

     15,038         10,014   
  

 

 

    

 

 

 

Total refining production (excluding internally-produced fuel)

     113,404         119,669   

Average sales price (dollars per gallon):

     

Gasoline

   $ 2.89       $ 2.94   

Distillate

   $ 3.04       $ 3.06   

 

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     Nine Months Ended
September 30, 2012
 
     ($ in millions)  
     (unaudited except
as otherwise
indicated)
 

Wynnewood Refinery Statements of Operations Data:

  

Net sales

   $ 2,380.6   

Cost of product sold(1)

     1,924.5   

Direct operating expenses(1)(2)

     83.6   

Schedule turnaround expense

     13.4   

Depreciation and amortization

     25.7   
  

 

 

 

Gross Profit(3)

   $ 333.4   

Plus:

  

Direct operating expenses and major scheduled turnaround expenses(1)

     97.0   

Depreciation and amortization

     25.7   
  

 

 

 

Refining margin(4)

   $ 456.1   

Operating income

   $ 319.1   

Wynnewood Refinery Key Operating Statistics:

  

Per crude oil throughput barrel:

  

Refining margin(4)

   $ 25.58   

Refining margin adjusted for FIFO impacts(7)

     26.28   

Gross profit

     18.70   

Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact)(8)

     20.15   

Direct operating expenses(1)(2)

     5.44   

Direct operating expenses (excluding major scheduled turnaround expenses)(9)

     4.69   

Direct operating expenses per barrel sold(6)

     4.91   

Barrels sold (barrels per day)

     72,087   

 

     Nine Months Ended
September 30,
2012
 

Wynnewood Refinery Throughput and Production Data(bpd):

  

Throughput:

  

Sweet

     45,592   

Medium

     19,492   

Heavy sour

     —     
  

 

 

 

Total crude oil throughput

     65,084   

Feedstocks and blendstocks

     3,000   
  

 

 

 

Total throughput

     68,084   

Production:

  

Gasoline

     33,225   

Distillate

     24,802   

Other (excluding internally-produced fuel)

     7,574   
  

 

 

 

Total refining production (excluding internally-produced fuel)

     65,601   

Average sales price (dollars per gallon):

  

Gasoline

   $ 2.93   

Distillate

   $ 3.08   

 

 

(1) Amounts are shown exclusive of depreciation and amortization.
(2)

Direct operating expense is presented on a per crude oil throughput basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which does

 

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not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(3) In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.
(4)

Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that management believes is important to investors in evaluating the performance of our refineries as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from our Combined Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance. For a reconciliation of refining margin per crude oil throughput barrel to net sales for the periods presented, see “Prospectus Summary—Non-GAAP Financial Measures.”

 

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(5) EBITDA and Adjusted 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 represents EBITDA adjusted for FIFO impacts (favorable) unfavorable (as described below), share-based compensation, and where applicable, Wynnewood acquisition transaction fees and integration expenses, major scheduled turnaround expenses, loss on disposition of assets, loss on extinguishment of debt 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:

 

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

Net income

  $ 64.6      $ 38.2      $ 480.3      $ 402.8      $ 540.7   

Add:

         

Interest expense and other financing costs

    43.8        49.7        53.0        39.2        56.0   

Income tax expense

    —          —          —          —          —     

Depreciation and amortization

    64.4        66.4        69.8        50.9        80.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  $ 172.8      $ 154.3      $ 603.1      $ 492.9      $ 677.1   

Add:

         

FIFO impacts (favorable), unfavorable(a)

    (67.9     (31.7     (25.6     1.5        54.3   

Share-based compensation

    2.5        11.5        8.9        8.0        15.6   

Loss on disposition of assets

    —          1.3        2.5        1.5        —     

Loss on extinguishment of debt

    2.1        16.6        2.1        2.1        —     

Wynnewood acquisition transaction fees and integration expenses

    —          —          5.2        —          10.3   

Major scheduled turnaround expenses

    —          1.2        66.4        12.2        34.6   

Unrealized (gain) loss on derivatives, net

    37.8        (0.6     (85.3     6.8        197.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 147.3      $ 152.6      $ 577.3      $ 525.0      $ 988.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

(6) Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.
(7)

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)

 

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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 FIFO impacts when crude oil prices decrease.

(8) 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 major 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.
(9) Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel is a measurement calculation 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.
(10) 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 118,048 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.
(11) Source: Data published by Platts and Oil Price Information Service and represents average pricing for the periods presented.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Net Sales. Net sales were $6,465.5 million for the nine months ended September 30, 2012 compared to $3,773.3 million for the nine months ended September 30, 2011. The increase of $2,692.2 million was primarily the result of higher overall sales volume. The higher sales volume is due to the inclusion of a full nine months’ sales for our Wynnewood refinery for the nine months ended September 30, 2012. Our average sales price per gallon for the nine months ended September 30, 2012 was $2.93 for gasoline and $3.07 for distillate as compared to the nine months ended September 30, 2011 average sales prices of $2.89 for gasoline and $3.04 for distillates.

 

    Nine Months Ended
September 30, 2012
    Nine Months Ended
September 30, 2011
    Total Variance     Volume
Variance
    Price
Variance
 
    Volume(1)     $ per barrel     Sales $     Volume(1)     $ per barrel     Sales $     Volume(1)     Sales $      
($ in millions other than per barrel data)        

Gasoline

    27.4      $ 123.18      $ 3,380.3        15.5      $ 121.36      $ 1,880.5        11.9      $ 1,499.8      $ 1,449.8      $ 50.0   

Distillate

    21.4      $ 128.98      $ 2,760.2        13.0      $ 127.77      $ 1,667.3        8.4      $ 1,092.9      $ 1,067.0      $ 25.9   

 

(1) Barrels in millions

 

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Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $5,191.0 million for the nine months ended September 30, 2012 compared to $3,078.5 million for the nine months ended September 30, 2011. The increase of $2,112.5 million was primarily the result of an increase in crude oil throughputs and an increase in crude oil prices. The increase in crude oil throughputs is due to the inclusion of a full nine months’ consumption at our Wynnewood refinery. Our average cost per barrel of crude oil consumed for the nine months ended September 30, 2012 was $92.76 compared to $91.58 for the comparable period of 2011, an increase of approximately 1.3%. Sales volume of refined fuels increased by approximately 73.4%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the nine months ended September 30, 2012, we had an unfavorable FIFO inventory impact of $54.3 million compared to an unfavorable FIFO inventory impact of $1.5 million for the comparable period of 2011.

Refining margin per barrel of crude oil throughput increased from $23.77 for the nine months ended September 30, 2011 to $26.34 for the nine months ended September 30, 2012. Refining margin adjusted for FIFO impact was $27.46 per crude oil throughput barrel for the nine months ended September 30, 2012, as compared to $23.82 per crude oil throughput barrel for the nine months ended September 30, 2011. Gross profit per barrel increased to $19.45 for the nine months ended September 30, 2012 as compared to gross profit per barrel of $17.10 in the equivalent period in 2011. The increase of our refining margin per barrel is due to an increase in the average sales prices of our produced gasoline and distillates, which was partially offset by an increase in our cost of consumed crude oil. Our average sales price for gasoline increased approximately 1.5% and our average sales price for distillates increased approximately 0.9% for the nine months ended September 30, 2012 over the comparable period in 2011. Consumed crude oil costs increased due to a 0.7% increase in WTI for the nine months ended September 30, 2012.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) were $253.1 million for the nine months ended September 30, 2012 compared to $144.0 million for the nine months ended September 30, 2011. The increase of $109.1 million was primarily the result of nine months of expenses for our Wynnewood refinery ($97.0 million), and an increase at our Coffeyville refinery of $12.2 million. The increase in expenses at our Coffeyville refinery is primarily related to turnaround expense ($8.9 million), production chemicals ($3.4 million) and labor costs ($3.2 million). Increases in direct operating expenses at our Coffeyville refinery were partially offset by decreases related to repairs and maintenance ($2.9 million) and other operating expenses ($0.4 million). Direct operating expenses per barrel of crude oil throughput for the nine months ended September 30, 2012 increased to $5.23 per barrel as compared to $4.93 per barrel for the nine months ended September 30, 2011.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and Coffeyville Resources and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $67.5 million for the nine months ended September 30, 2012 as compared to $31.4 million for the nine months ended September 30, 2011. This $36.1 million increase was primarily the result of higher payroll-related costs due to growth in staff, integration costs related to WEC and overall higher costs associated with acquiring WEC.

 

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Operating Income. Operating income was $873.5 million for the nine months ended September 30, 2012, as compared to $468.5 million for the nine months ended September 30, 2011. This increase of $405.0 million was primarily the result of an increase in the refining margin ($579.7 million). The increase in refining margin was partially offset by an increase in direct operating expenses ($109.1 million), depreciation and amortization ($29.5 million) and selling, general and administrative expenses ($36.1 million)

Interest Expense. Interest expense for the nine months ended September 30, 2012 was $56.0 million as compared to interest expense of $39.2 million for the nine months ended September 30, 2011. This $16.8 million increase resulted primarily from higher interest cost due to the additional $200.0 million of First Lien Notes issued by Coffeyville Resources and Coffeyville Finance in December 2011 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Notes.

Realized Gain (Loss) on Derivatives, net. For the nine months ended September 30, 2012, we recorded a $80.4 million realized loss on derivatives compared to an $18.3 million realized loss on derivatives for the nine months ended September 30, 2011. The change was primarily attributable to realized losses on our commodity swaps. We entered into several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011.

Unrealized Gain (Loss) on Derivatives, net. For the nine months ended September 30, 2012, we recorded a $197.0 million unrealized loss on derivatives compared to a $6.8 million unrealized loss on derivatives for the nine months ended September 30, 2011. The change was primarily attributable to larger unrealized losses on our commodity swaps. We entered into several over-the-counter commodity swaps to fix the margin on a portion of future gasoline and distillate production beginning in the fourth quarter of 2011.

Net Income. Net income for the nine months ended September 30, 2012 was $540.7 million as compared to net income of $402.8 million for the nine months ended September 30, 2011, an increase of $137.9 million.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 (Including Wynnewood Refinery Beginning on December 16, 2011)

Net Sales. Net sales were $4,752.8 million for the year ended December 31, 2011, compared to $3,905.6 million for the year ended December 31, 2010. The increase of $847.2 million was primarily the result of higher product prices which were partially offset by lower overall sales volumes. Overall sales volumes of refined fuels and propane decreased 11.5%. The lower overall sales volumes were primarily the result of the major maintenance turnaround at our Coffeyville refinery in the fall of 2011. Our average sales price per gallon of $2.82 for gasoline and $3.03 for distillates increased by 33.9% and 38.0%, respectively, as compared to the year ended December 31, 2010.

 

    Year ended December 31, 2011     Year ended December 31, 2010     Total Variance     Volume
Variance
    Price
Variance
 
    Volume(1)     $ per barrel     Sales $     Volume(1)     $ per barrel     Sales $     Volume(1)     Sales $      
($ in millions except per barrel data)        

Gasoline

    19.7      $ 118.35      $ 2,337.2        23.1      $ 88.39      $ 2,038.2        (3.4   $ 299.0      $ (292.7   $ 591.7   

Distillate

    16.6      $ 127.25      $ 2,114.8        18.6      $ 92.22      $ 1,718.3        (2.0   $ 396.5      $ (185.6   $ 582.1   

 

(1) Barrels in millions

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $3,927.6 million for the year ended December 31, 2011, compared to $3,539.8 million for the year ended December 31, 2010. The increase of $387.8 million was primarily the result of a significant increase in crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2011 was $92.09, compared to $76.13 for the year ended December 31, 2010, an increase of approximately 21.0%. Partially

 

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offsetting the rise in crude oil consumed cost was the decrease of sales of refined fuels by approximately 11.5%. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. For the year ended December 31, 2011, we had a favorable FIFO impact of $25.6 million compared to a favorable FIFO impact of $31.7 million for the year ended December 31, 2010.

Refining margin per barrel of crude oil throughput increased from $8.84 for the year ended December 31, 2010 to $21.80 for the year ended December 31, 2011. Refining margin adjusted for FIFO impact was $21.12 per barrel of crude oil throughput for the year ended December 31, 2011, as compared to $8.07 per crude oil throughput barrel for the year ended December 31, 2010. Gross profit per barrel increased to $13.41 for the year ended December 31, 2011, as compared to gross profit per barrel of $3.54 in the comparable period in 2010. The increase in our refining margin per barrel was due to an increase in the average sales prices of our produced gasoline and distillates, which was greater than the increase in our cost of consumed crude oil. Our average sales price for gasoline increased approximately 33.9% and our average sales price for distillates increased approximately 38.0%. Consumed crude oil costs rose due to a 19.5% increase in WTI for the year ended December 31, 2011 over the year ended December 31, 2010.

Effective January 1, 2011, our Coffeyville refinery became subject to the provisions of the Renewable Fuel Standards, which mandates the use of renewable fuels. To meet this mandate, we must either blend renewable fuels into gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. As a result of this mandate, we incurred an additional $19.0 million of expense for the year ended December 31, 2011 which is reflected in our cost of product sold (exclusive of depreciation and amortization).

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) 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. Direct operating expenses (exclusive of depreciation and amortization) were $247.7 million for the year ended December 31, 2011, compared to $153.1 million for the year ended December 31, 2010. The increase of $94.6 million was the result of increases in expenses primarily related with turnaround maintenance ($66.4 million), environmental compliance ($7.8 million), repairs and maintenance ($6.4 million), labor ($6.2 million), outside services ($2.5 million), catalyst and chemicals ($2.4 million), operating supplies ($2.2 million), rent ($1.3 million) and other direct operating expenses ($0.6 million). On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2011 increased to $6.54 per barrel as compared to $3.70 per barrel for the year ended December 31, 2010, principally due to the net dollar increase in expenses from year to year as detailed above.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and Coffeyville Resources and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $51.0 million for the year ended December 31, 2011 as compared to $43.1 million for the year ended December 31, 2009. This $7.9 million increase in selling, general and administrative expenses over the comparable period was primarily the result of higher payroll-related costs due to growth in staff and integration costs related to WEC, offset in part by lower share-based compensation expenses resulting from the change in the composition of long-term incentive plans.

Operating Income. Operating income was $456.7 million for the year ended December 31, 2011 as compared to operating income of $103.2 million for the year ended December 31, 2010. This increase of $353.5 million was primarily the result of an increase in refining margin ($459.4 million), partially offset by an increase in direct operating expenses ($94.6 million), an increase in depreciation and amortization ($3.5 million) and an increase in selling, general and administrative expense ($7.9 million).

 

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Interest Expense. Interest expense for the year ended December 31, 2011 was $53.0 million as compared to interest expense of $49.7 million for the year ended December 31, 2010. This $3.3 million increase resulted primarily from higher interest cost by having a full year of interest on the $500.0 million of Notes issued in April 2010 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Notes.

Realized Gain (Loss) on Derivatives, net. For the year ended December 31, 2011, we recorded a $7.2 million realized loss on derivatives compared to a $2.1 million realized loss on derivatives for the year ended December 31, 2010. The change was primarily attributable to realized losses on our commodity swaps.

Unrealized Gain (Loss) on Derivatives, net. For the year ended December 31, 2011, we recorded an $85.3 million unrealized gain on derivatives compared to a $0.6 million unrealized gain on derivatives for the year ended December 31, 2010. The change was primarily attributable to larger unrealized gains on our commodity swaps. We entered into several over-the-counter commodity swaps to fix the margin of a portion of future gasoline and distillate production beginning in the fourth quarter of 2011.

Loss on Extinguishment of Debt. For the year ended December 31, 2011, we recorded a $2.1 million loss on extinguishment of debt compared to $16.6 million for the year ended December 31, 2010. This decrease in the loss on extinguishment of debt was primarily the result of a 2.0% premium paid in connection with unscheduled prepayments and payoff of the tranche D term loan in 2010, which contributed $9.6 million to 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 Notes, $0.1 million of third party costs were immediately expensed. In December 2010, Coffeyville Resources made a voluntary unscheduled principal payment on the 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.

Net Income. For the year ended December 31, 2011, net income was $480.3 million as compared to net income of $38.2 million for the year ended December 31, 2010, an increase of $442.1 million.

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Net Sales. Net sales were $3,905.6 million for the year ended December 31, 2010, compared to $2,936.5 million for the year ended December 31, 2009. The increase of $969.1 million was primarily the result of higher refined product prices and overall higher sales volumes. Overall sales volumes of refined fuels and propane for the year ended December 31, 2010 increased 5%, as compared to the year ended December 31, 2009. Our average sales price per gallon for the year ended December 31, 2010 for gasoline of $2.10 and distillate of $2.20 increased by 25% and 31%, respectively, as compared to the year ended December 31, 2009. The Coffeyville refinery operated at 99% of its capacity in 2010 despite 16 days of unscheduled outage of its FCCU that reduced crude oil runs in the second and fourth quarters and a scheduled eight day turnaround of one of its crude oil units in the first quarter.

 

    Year ended December 31, 2010     Year ended December 31, 2009     Total Variance     Volume
Variance
    Price
Variance
 
    Volume(1)     $ per barrel     Sales $     Volume(1)     $ per barrel     Sales $     Volume(1)     Sales $      
($ in millions
except per
barrel data)
                                                     

Gasoline

    23.1      $ 88.39      $ 2,038.2        22.9      $ 70.40      $ 1,614.6        0.1      $ 423.6      $ 8.8      $ 414.8   

Distillate

    18.6      $ 92.22      $ 1,718.3        17.0      $ 70.74      $ 1,200.4        1.7      $ 517.9      $ 117.7      $ 400.2   

 

(1) Barrels in millions

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, feedstocks and blendstocks, purchased products for

 

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resale, and transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $3,539.8 million for the year ended December 31, 2010, compared to $2,515.9 million for the year ended December 31, 2009. The increase of $1,023.9 million was primarily the result of a significant increase in crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2010 was $76.13, compared to $57.46 for the year ended December 31, 2009, an increase of approximately 32%. Sales volumes of refined fuels increased approximately 5%. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. For the year ended December 31, 2010, we had a favorable FIFO impact of $31.7 million compared to a favorable FIFO impact of $67.9 million for the year ended December 31, 2009.

Refining margin per barrel of crude oil throughput decreased from $10.65 for the year ended December 31, 2009 to $8.84 for the year ended December 31, 2010. Refining margin adjusted for FIFO impact was $8.07 per crude oil throughput barrel for the year ended December 31, 2010, as compared to $8.93 per crude oil throughput barrel for the year ended December 31, 2009. Gross profit per barrel decreased to $3.54 for the year ended December 31, 2010 as compared to gross profit per barrel of $5.42 in the equivalent period in 2009. The decline of our refining margin per barrel is due to an increase in our cost of consumed crude oil, partially offset by an increase in the average sales prices of our produced gasoline and distillates. Consumed crude oil costs rose due to a 28% increase in WTI and a 27% decrease in our consumed crude oil discount to WTI as a result of our Coffeyville refinery processing a sweeter crude oil slate for the year ended December 31, 2010 over the year ended December 31, 2009 and a weakening of the contango market in the U.S. crude oil market. Our average sales price of gasoline increased approximately 25% and our average sales price for distillates increased approximately 31% for the year ended December 31, 2010 over the comparable period of 2009.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the operations of our refineries, such as energy and utility costs, property taxes, catalyst and production chemicals costs, repairs and maintenance (turnaround), labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) were $153.1 million for the year ended December 31, 2010, compared to $142.2 million for the year ended December 31, 2009. The increase of $10.9 million was the result of increases in expenses primarily associated with labor ($6.4 million), repairs and maintenance ($4.8 million), utilities and energy ($4.6 million) and rent ($1.5 million), offset by decreases in expenses associated with production chemicals ($2.7 million), flood-related costs ($1.6 million), insurance ($1.2 million) and other direct operating expenses ($0.9 million). On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2010 increased to $3.70 per barrel, as compared to $3.60 per barrel for the year ended December 31, 2009, principally due to the net dollar increase in expenses from year to year as detailed above.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and Coffeyville Resources and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $43.1 million for the year ended December 31, 2010 as compared to $40.0 million for the year ended December 31, 2009. This $3.1 million increase in selling, general and administrative expenses over the comparable period was primarily due to increases in share-based compensation expense and a loss on disposition of assets in 2010. The increase in share-based compensation expense was primarily the result of an increase in CVR Energy’s share price. The loss on disposition of assets related to the write-off of a capital project during the second quarter of 2010. These increases were partially offset by a decrease in bank charges resulting from the termination of the first priority funded letter of credit facility in 2009.

Operating Income. Operating income was $103.2 million for the year ended December 31, 2010 as compared to operating income of $174.0 million for the year ended December 31, 2009. This decrease of

 

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$70.8 million was primarily the result of a decline in the refining margin ($54.8 million), an increase in direct operating expenses ($10.9 million), an increase in depreciation and amortization ($2.0 million), and an increase in selling, general and administrative expenses ($3.1 million).

Interest Expense. Interest expense for the year ended December 31, 2010 was $49.7 million as compared to interest expense of $43.8 million for the year ended December 31, 2009. This $5.9 million increase resulted primarily from Coffeyville Resources’ issuance of the Notes on April 6, 2010 in an aggregate principal amount of $500.0 million. Coffeyville Resources paid off the outstanding tranche D term debt totaling $453.3 million in April 2010 as a result of the issuance of the Notes. The Notes were issued under a first and second lien arrangement. The $275.0 million of First Lien Notes accrue interest at 9.0% and the $225.0 million of Second Lien Notes accrue interest at 10.875%. This compares to an average 2009 long-term debt balance of $481.3 million which accrued interest at a weighted-average interest rate of approximately 8.64%. Also impacting interest expense was the increased amortization of deferred financing costs and original issue discount associated with the Notes. Additionally, a portion of the increase in amortization for the year ended December 31, 2010 was the result of costs incurred in connection with the third and fourth amendments to the first priority credit facility completed in the fourth quarter of 2009 and first quarter of 2010, respectively. For the year ended December 31, 2010, amortization of deferred financing costs associated with the first priority tranche D loans and revolving credit facility totaling $1.6 million were incurred, compared to $1.0 million for the year ended December 31, 2009. The incremental impact to interest expense, as a result of the amortization of the deferred financing costs and original issue discount associated with the issuance of the Notes in April 2010, was an increase of approximately $2.1 million for the year ended December 31, 2010.

Realized Gain (Loss) on Derivatives, net. For the year ended December 31, 2010, we recorded a $2.1 million realized loss on derivatives compared to a $27.5 million realized loss on derivatives for the year ended December 31, 2009. The change was primarily attributable to realized losses on the cash flow swap. For the year ended December 31, 2010, there was no impact, as the cash flow swap was terminated by Coffeyville Resources in the fourth quarter of 2009. A realized gain of $0.7 million recorded for the year ended December 31, 2010 was primarily attributable to other commodity derivative activities. For the year ended December 31, 2009, we recorded a realized loss of approximately $14.3 million related to the cash flow swap and a realized loss of approximately $6.6 million related to other commodity derivative activities. The remaining year-over-year difference is attributable to an interest rate swap which was terminated by Coffeyville Resources in June 2010. The interest rate swap resulted in realized losses of $2.9 million in 2010 and $6.5 million in 2009.

Unrealized Gain (Loss) on Derivatives, net. For the year ended December 31, 2010, we recorded a $0.6 million unrealized gain on derivatives compared to a $37.8 million unrealized loss on derivatives for the year ended December 31, 2009. The change was primarily attributable to unrealized losses on Cash Flow Swap. For the year ended December 31, 2010, there was no impact to the combined financial statements as the Cash Flow Swap was terminated in the fourth quarter of 2009. An unrealized loss of $2.2 million recorded for the year ended December 31, 2010 was primarily attributable to other commodity derivative activities. For the year ended December 31, 2009, we recorded an unrealized loss of approximately $40.9 million related to the Cash Flow Swap and an unrealized loss of approximately $1.8 million related to other commodity derivative activities. The remaining year-over-year difference is attributable to an interest rate swap which was terminated by Coffeyville Resources in June 2010. The interest rate swap resulted in unrealized gains of $2.8 million in 2010 and $5.0 million in 2009.

Loss on Extinguishment of Debt. For the year ended December 31, 2010, we recorded a $16.6 million loss on extinguishment of debt compared to a $2.1 million loss for the year ended December 31, 2009. This increase in the loss on extinguishment of debt was primarily the result of a 2.0% premium paid in connection with unscheduled prepayments and payoff of the tranche D term loan, which contributed $9.6 million to 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 Notes, $0.1 million of third party costs were immediately expensed. In December 2010,

 

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Coffeyville Resources made a voluntary unscheduled principal payment on the 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. This compares to a write-off of $2.1 million of previously deferred financing costs in connection with the reduction and eventual termination of the first priority funded credit facility in the fourth quarter of 2009.

Net Income. For the year ended December 31, 2010, net income was $38.2 million as compared to net income of $64.6 million for the year ended December 31, 2009, a decrease of $26.4 million, based on the factors in the foregoing discussion.

Liquidity and Capital Resources

Liquidity

We expect that our future principal uses of cash will be for working capital, capital expenditures, funding our debt service obligations and, following the completion of this offering, paying distributions to our unitholders. Coffeyville Resources uses a centralized approach to cash management and has historically provided cash as needed to support our operations and has retained excess cash earned by our operations. As a result, amounts owed to or from Coffeyville Resources have been reflected as a component of divisional equity. We believe that our cash flows from operations and existing cash and cash equivalents, along with borrowings, as necessary, under the New ABL Credit Facility and the $150 million senior unsecured revolving credit facility we expect to enter into with Coffeyville Resources as lender, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months, including the integration of the Wynnewood refinery. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control. Please read “—Capital Spending” for a further discussion of the impact on liquidity.

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 a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance our growth externally, the growth in our business, and our liquidity, may be negatively impacted.

Cash Flows

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

 

     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012  
    

($ in millions)

 
                       (unaudited)  

Net cash 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

     3.8        (146.3     303.6        (393.7     (640.0
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ 2.1      $ (0.4   $ 0.4      $ (2.3   $ 76.8   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.

 

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Nine Months Ended September 30, 2012 and 2011

Cash Flows Provided by Operating Activities

Net cash flows provided by operating activities for the nine months ended September 30, 2012 was $799.2 million. The positive net cash flow from operating activities was primarily driven by operating income of $873.5 million, which was primarily the result of higher operating margins. This positive cash flow from operating activities was partially offset by unfavorable changes in trade working capital. Trade working capital for the nine months ended September 30, 2012 resulted in a cash outflow of approximately $71.5 million as a result of a decrease in accounts payable ($90.6 million) coupled with an increase in accounts receivable ($99.5 million), offset by a decrease in inventories ($118.6 million).

Net cash flows provided by operating activities for the nine months ended September 30, 2011 was $424.9 million. The positive cash flow from operating activities generated over this period was primarily driven by $468.5 million of operating income. This positive operating income was primarily indicative of the operating margins for the period. The positive operating cash flow for the period was partially offset by unfavorable changes in trade working capital. Trade working capital for the nine months ended September 30, 2011 resulted in a reduction of cash flows of $43.0 million which was primarily attributable to the increase in inventories ($56.9 million) and an increase in accounts receivable ($1.6 million), both of which were partially offset by an increase in accounts payable of $15.5 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2012 was $82.4 million compared to $33.5 million for the nine months ended September 30, 2011. The increase in investing activities was primarily the result of an increase in capital expenditures of $49.2 million due to projects at the Coffeyville refinery, construction of crude oil storage in Cushing, Oklahoma and incremental capital spending incurred for the Wynnewood refinery.

Cash Flows Used In Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2012 was approximately $640.0 million compared to $393.7 million for the nine months ended September 30, 2011. Coffeyville Resources has historically provided cash as necessary to support our operations and has retained excess cash earned by our operations. Cash received or paid by Coffeyville Resources on our behalf is recorded as net contributions from or net distributions to parent as a component of divisional equity which are reflected as a financing activity in the Combined Statement of Cash Flows.

During the nine months ended September 30, 2012, the use of cash for financing activities was primarily driven by $637.2 million in net distributions to Coffeyville Resources. Additionally, financing costs of approximately $2.0 million were paid associated with increasing the borrowing capacity of the ABL credit facility and the issuance of additional First Lien Notes in December 2011.

During the nine months ended September 30, 2011, the use of cash for financing activities was primarily driven by $385.1 million in net distributions to Coffeyville Resources. Additional uses of cash for the nine months ended September 30, 2011 included financing costs of approximately $5.8 million associated with the ABL credit facility and a repurchase of $2.7 million of the Notes in accordance with the terms of a tender offer.

For the nine months ended September 30, 2012, there were no borrowings or repayments under our ABL credit facility. As of September 30, 2012, there were no short-term borrowings outstanding under our ABL credit facility.

 

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Years Ended December 31, 2011, 2010 and 2009

Cash Flows Provided by Operating Activities

Net cash flows provided by operating activities for the year ended December 31, 2011 were approximately $352.7 million. The positive cash flow from operating activities generated over this period was largely driven by operating income of $456.7 million, offset by unfavorable changes in trade working capital and other working capital. Trade working capital for the year ended December 31, 2011 resulted in a net cash outflow of approximately $105.2 million attributable to an increase in inventory of $172.0 million, offset by a decrease in accounts receivable of $59.7 million and an increase in accounts payable of $7.1 million. Other working capital activities resulted in a net cash outflow of approximately $25.4 million. This outflow was primarily driven by an increase in prepaid expenses and other current assets ($14.9 million) and a decrease in other current liabilities ($6.9 million).

Net cash flows provided by operating activities for the year ended December 31, 2010 were approximately $167.0 million. The positive cash flow from operating activities generated over this period was primarily driven by $103.2 million in operating income coupled with a favorable change in trade working capital. Trade working capital for the year ended December 31, 2010 resulted in a net cash inflow of approximately $33.1 million, primarily attributable to a decrease in inventory of $25.3 million and an increase accounts payable of $39.6 million, partially offset by an increase in accounts receivable of $31.8 million.

Net cash flows provided by operating activities for the year ended December 31, 2009 were $31.9 million. The positive cash flow from operating activities generated over this period was primarily driven by $174 million of operating income, offset by unfavorable changes in trade working capital and other working capital. Trade working capital for the year ended December 31, 2009 resulted in a net cash outflow of $132.4 million, primarily attributable to an increase in inventory of $130.3 million and an increase in accounts receivable of $16.2 million, partially offset by an increase in accounts payable of $14.1 million. Other working capital activities resulted in a net cash outflow of $9.7 million. This outflow was primarily driven by a decrease in the net swap payable ($65.0 million) following settlement of the cash flow swap during the year, offset by decreases in restricted cash ($34.6 million), prepaid expenses and other current assets ($10.1 million) and insurance receivables ($7.5 million), and increases in other current liabilities ($5.7 million).

Cash Flows Used In Investing Activities

Net cash used in investing activities for the years ended December 31, 2011, 2010 and 2009 was approximately $655.9 million, $21.1 million and $33.6 million, respectively. Net cash used for investing activities principally relates to capital expenditures. The increase in investing activities for the year ended December 31, 2011 was the result of $587.1 million cash consideration paid for the acquisition of Gary-Williams Energy Corporation.

Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities for the year ended December 31, 2011 was approximately $303.6 million. Coffeyville Resources has historically provided cash as necessary to support our operations and has retained excess cash earned by our operations. Cash received or paid by Coffeyville Resources on our behalf is recorded as net contributions from or net distributions to parent as a component of divisional equity which are reflected as a financing activity in the Combined Statement of Cash Flows.

The net cash provided by financing activities for the year ended December 31, 2011 was primarily attributable to $110.6 million in net contributions from Coffeyville Resources and the receipt of $206.0 million from the issuance of the additional Notes. These inflows from financing activities were offset by approximately $10.3 million of issuance costs paid during the period associated with the additional First Lien Notes. Additionally, we repurchased $2.7 million of the Notes in accordance with the terms of a tender offer.

 

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Net cash used in financing activities for the year ended December 31, 2010 was approximately $146.3 million. The net use of cash for the year ended included $116.3 million in net distributions to Coffeyville Resources. During 2010 approximately $479.5 million in long-term debt under the first-priority credit facility was paid off. This payoff was made possible by the issuance of the Notes that resulted in net proceeds of $485.7 million. In addition, $8.8 million was paid for financing costs in connection with the fourth amendment to the first priority credit facility and issuance of the Notes. In December 2010, a principal payment of $27.5 million was made on the Notes.

Net cash provided by financing activities for the year ended December 31, 2009 was approximately $3.8 million. The net cash provided by financing activities for the year ended December 31, 2009 was comprised of $12.6 million in net contributions received from Coffeyville Resources, offset by scheduled payments of $4.8 million on long-term debt and debt issuance cost payments of $4.0 million related to financing costs associated with an amendment to the first priority credit facility.

Borrowing Activities

New Notes. On October 23, 2012, CVR Refining, LLC and Coffeyville Finance (as “Issuers”) 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.

The New Notes were issued at 100% of their principal amount. The New Notes were issued pursuant to an indenture (the “New Indenture”), dated October 23, 2012, among CVR Refining, LLC and Coffeyville Finance, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the “New Notes Trustee”). The Notes were fully and unconditionally guaranteed by Coffeyville Resources and substantially all of CVR Refining, LLC’s subsidiaries (the “Guarantors” and, together with the Issuers, the “Credit Parties”). Coffeyville Resources will be released as a guarantor in connection with the closing of this offering.

The New Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the New Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date. The obligations of the Credit Parties under the New Notes and the guarantees were initially secured by liens on substantially all of the Credit Parties’ assets. The security interests will be released in upon the repayment of the Second Lien Notes in connection with the closing of this offering.

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

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

In the event of a “change of control” as defined in the New Indenture, the Issuers are required to offer to buy back all of the Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of CVR Refining, LLC

 

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to any person other than qualifying owners (as defined in the New Indenture), (2) liquidation or dissolution of CVR Refining, LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stock of CVR Refining, LLC.

The New Indenture imposes covenants that restrict the ability of the Credit Parties to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the New Notes are rated investment grade by both S&P and Moody’s. However, such covenants would be reinstituted if the Notes subsequently lost their investment grade rating. In addition, the New Indenture contains customary events of default, the occurrence of which would result in, or permit the Trustee or holders of at least 25% of the New Notes to cause the acceleration of the applicable Notes, in addition to the pursuit of other available remedies.

The New Indenture prohibits us from making distributions to unitholders if any default or event of default (as defined in the New Indenture) exists. In addition, the New 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 New 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 New Indenture.

Senior Secured Notes. On April 6, 2010, Coffeyville Resources and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due April 1, 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due April 1, 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, the Issuers made a voluntary unscheduled principal payment of $27.5 million on the First Lien Notes. As a result of this payment, the Issuers were required to pay a 3.0% premium totaling approximately $0.8 million. Additionally, an adjustment was made to CVR Energy’s previously deferred financing costs, underwriting discount and original issue discount of approximately $0.8 million. The premium payment and write-off of previously deferred financing costs, underwriting discount and original issue discount were recognized as a loss on extinguishment of debt. On May 16, 2011, the Issuers repurchased $2.7 million of the First Lien Notes at a purchase price of 103% of the outstanding principal amount. On December 15, 2011, the Issuers issued an additional $200.0 million aggregate principal amount of 9% First Lien Senior Secured Notes to partially fund the Wynnewood Acquisition. The additional First Lien Notes were issued at 105% of their principal amount. As the Notes were incurred for the benefit of our operations, all debt and associated costs have been allocated to CVR Refining. As of September 30, 2012, the Notes had an aggregate principal balance of $669.8 million and a net carrying value of $674.5 million. On October 23, 2012, we repurchased approximately $323.0 million of our First Lien Notes pursuant to a tender offer and we redeemed the remaining $124.1 million of outstanding First Lien Notes on November 23, 2012.

The First Lien Notes were issued pursuant to an indenture (the “First Lien Notes Indenture”), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the “First Lien Notes Trustee”). The Second Lien Notes were issued pursuant to an indenture (the “Second Lien Notes Indenture” and together with the First Lien Notes Indenture, the “Indentures”), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the “Second Lien Notes Trustee” and in reference to the Indentures, the “Trustee”). The Notes were originally fully and

 

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unconditionally guaranteed by substantially all of CVR Energy’s subsidiaries (the “Guarantors” and, together with the Issuers, the “Credit Parties”). CVR Partners was released as a guarantor in connection with CVR Partners’ initial public offering in April 2011.

The First Lien Notes bear interest at a rate of 9.0% per annum and mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes bear interest at a rate of 10.875% per annum and mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year, to holders of record at the close of business on March 15 and September 15, as the case may be, immediately preceding each such interest payment date.

The Issuers have the right to redeem the First Lien Notes at a redemption price of (i) 106.750% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2012; (ii) 104.500% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; and (iii) 100% of the principal amount, if redeemed on or after April 1, 2014, in each case, plus any accrued and unpaid interest. The net proceeds from the issuance of the New Notes were used to purchase and redeem the First Lien Notes.

The Issuers have the right to redeem the Second Lien Notes at redemption prices during the applicable periods set forth below:

 

   

On or after April 1, 2013, some or all of the Second Lien Notes may be redeemed at a redemption price of (i) 108.156% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; (ii) 105.438% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2014; (iii) 102.719% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2015; and (iv) 100% of the principal amount if redeemed on or after April 1, 2016, in each case, plus any accrued and unpaid interest;

 

   

Prior to April 1, 2013, up to 35% of the Second Lien Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 110.875% of the principal amount thereof, plus any accrued and unpaid interest; and

 

   

Prior to April 1, 2013, some or all of the Second Lien Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.

We expect to redeem the Second Lien Notes at or following the closing of this offering with a combination of proceeds from this offering and cash on hand.

In the event of a “change of control” as defined in the Indentures, the Issuers are required to offer to buy back all of the Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of “all or substantially all of the assets of CVR Energy” to any person other than permitted holders, (as defined in the Indenture), (2) liquidation or dissolution of Coffeyville Resources, (3) any person, other than a permitted holder, directly or indirectly acquiring 50% of the voting stock of Coffeyville Resources or (4) the first day when a majority of the directors of Coffeyville Resources or CVR Energy are not Continuing Directors (as defined in the Indentures). Continuing Directors are generally our existing directors and directors approved by the then-Continuing Directors.

The definition of “change of control” specifically excludes a transaction where CVR Energy becomes a subsidiary of another company, so long as (1) CVR Energy’s stockholders own a majority of the surviving parent or (2) no one person owns a majority of the common stock of the surviving parent following the merger.

The acquisition of a majority of the common stock of CVR Energy by affiliates of Icahn Enterprises required the Issuers to make an offer to repurchase all of the Issuers’ outstanding Notes. On June 4, 2012, the Issuers offered to purchase all or any part of the Notes, at a cash purchase price of 101.0% of the aggregate principal amount of the Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Notes tendered.

 

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The Indentures also allowed CVR Energy to sell, spin-off or complete an initial public offering of CVR Partners, as long as the Issuers offered to buy back a percentage of the Notes as described in the Indentures. In April 2011, CVR Partners completed an initial public offering of common units. As a result, under the terms of the Indentures, the Issuers were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. Holders of $2.7 million of the Notes tendered their Notes to CVR Energy. CVR Energy repurchased the Notes in accordance with the terms of the tender offer.

The Indentures impose covenants that restrict the ability of the Credit Parties to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the Notes are rated investment grade by both S&P and Moody’s. However, such covenants would be reinstituted if the Notes subsequently lost their investment grade rating. In addition, the Indentures contain customary events of default, the occurrence of which would result in, or permit the Trustee or holders of at least 25% of the First Lien Notes or Second Lien Notes to cause the acceleration of the applicable Notes, in addition to the pursuit of other available remedies. The Credit Parties were in compliance with the covenants as of September 30, 2012.

The obligations of the Credit Parties under the Notes and the guarantees are secured by liens on substantially all of the Credit Parties’ assets. The First Lien Notes are secured by first-priority liens on our fixed assets and a second priority lien on our inventory. The liens granted in connection with the Second Lien Notes rank junior to the liens in respect of the First Lien Notes.

ABL Credit Facility. Coffeyville Resources entered into its ABL credit facility on February 22, 2011, which was expanded to a $400.0 million facility on December 15, 2011 in connection with the Wynnewood Acquisition. On December 20, 2012, we amended and restated the ABL credit facility as discussed below. The ABL credit facility provided for borrowings, letter of credit issuances and a feature that permitted an increase of borrowings up to an additional $100.0 million (in the aggregate) subject to additional lender commitments. Prior to its amendment and restatement, the ABL credit facility was scheduled to mature in August 2015 was used to finance our ongoing working capital, capital expenditures, letter of credit issuances and general needs and included, among other things, a letter of credit sublimit equal to 90% of the total commitment. As the facility was maintained for the benefit of our operations, costs and any borrowings under the facility have been allocated to us. As of September 30, 2012, Coffeyville Resources had availability under the ABL Credit Facility of $372.8 million and had letters of credit outstanding of approximately $27.2 million. There were no borrowings outstanding under the ABL credit facility as of September 30, 2012.

Borrowings under the facility bore interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility could range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility was determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

Under its terms, the lenders under the ABL credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).

The ABL credit facility also contained customary covenants for a financing of its type that limit, subject to certain exceptions, the incurrence of additional indebtedness, creation of liens on assets and the ability to dispose assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. It also contained a fixed charge coverage ratio financial covenant that is triggered when

 

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borrowing base excess availability is less than certain thresholds, as defined under the facility. Coffeyville Resources was in compliance with the covenants of the ABL credit facility as of September 30, 2012.

In connection with the change in control described above, Coffeyville Resources, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to the ABL credit facility effective as of May 7, 2012 (the “ABL First Amendment”), pursuant to which the parties agreed to exclude the acquisition of Shares by affiliates of Icahn Enterprises from the definition of change of control as provided in the ABL credit facility. Absent the ABL First Amendment, the change in control of CVR Energy described above would have triggered an event of default under the ABL credit facility.

New ABL Credit Facility. On December 20, 2012, we entered into an amended and restated ABL 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. The borrowing-base components, advance rates, prepayment provisions, collateral provisions, affirmative covenants and negative covenants in the New ABL Credit Facility are substantially similar to the corresponding provisions in the ABL credit facility. The New ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00. The New ABL Credit Facility has a five-year maturity and will be used for working capital and other general corporate purposes (including permitted acquisitions).

Borrowings under the New ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The New ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. We will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.

Intercompany Credit Facility. 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 to be used to fund growth capital expenditures. The intercompany credit facility will be for a term of six years, and bear interest at a rate of LIBOR plus 3% per annum.

The intercompany credit facility will contain covenants that require us to, among other things, notify Coffeyville Resources of the occurrence of any default or event of default and provide Coffeyville Resources with information in respect of our business and financial status as it may reasonably require, including, but not limited to, copies of our unaudited quarterly financial statements and our audited annual financial statements.

In addition, the intercompany credit facility contains customary events of default, including, among others, failure pay any sum payable when due; the occurrence of a default of other indebtedness in excess of $25.0

 

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million; and the occurrence of an event that results in either (i) Coffeyville Resources no longer directly or indirectly controlling our general partner, or (ii) Coffeyville Resources and its affiliates no longer owning a majority of our equity interests.

Capital Spending

We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.

The following table summarizes our total actual combined capital expenditures for the year ended December 31, 2011 and our estimate of capital expenditures for the years ended December 31, 2012, 2013 and 2014:

 

     Actual      Estimated  
   2011      2012      2013      2014  
     ($ in millions)  

Coffeyville refinery:

           

Maintenance

   $ 49.7       $ 57.6       $ 81.7       $ 96.8   

Growth

     6.8         2.4         14.3         8.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital (excluding turnaround expenditures)

     56.5         60.0         96.0         105.1   

Wynnewood refinery:(1)

           

Maintenance

     0.5         68.6         96.2         114.7   

Growth

     —           3.1         19.9         29.5   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital (excluding turnaround expenditures)

     0.5         71.7         116.1         144.2   

Other petroleum:

           

Maintenance

     0.4         7.9         6.3         4.9   

Growth

     11.4         22.1         13.3         6.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital (excluding turnaround expenditures)

     11.8         30.0         19.6         11.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total business capital (excluding major scheduled turnaround expense)

   $ 68.8       $ 161.7       $ 231.7       $ 261.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Major scheduled turnaround expense

     66.4         121.2         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital spending (including major scheduled turnaround expense)

   $ 135.2       $ 282.9       $ 231.7       $ 261.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) The amounts reported for the Wynnewood refinery in 2011 represent only costs incurred during the post Wynnewood Acquisition period of December 16, 2011 through December 31, 2011.

We expect to spend approximately $160.0 million to $165.0 million (not including capitalized interest) on capital expenditures in 2012. Of this amount $60.0 million to $65.0 million is expected to be spent for the Coffeyville refinery which includes approximately $55.0 million to $60.0 million of maintenance capital. Approximately $70.0 million to $80.0 million is expected to be spent on capital for the Wynnewood refinery. Included in our expected capital spend is approximately $15.0 million for further expansion of tank storage in Cushing, Oklahoma.

During the first quarter of 2012, the Coffeyville refinery completed the second phase of a scheduled two-phase turnaround. We incurred total major scheduled turnaround expenses of approximately $21.2 million in connection with the turnaround in 2012. The Wynnewood refinery began turnaround maintenance in the fourth

 

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quarter of 2012 and completed it in December 2012. We incurred approximately $105.0 million of expenses during 2012 related to the Wynnewood refinery’s turnaround.

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

Contractual Obligations

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of September 30, 2012 relating to the Notes, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following September 30, 2012 and thereafter. As of September 30, 2012, there were no amounts outstanding under the ABL credit facility. The following table assumes no borrowings are made under the New ABL credit facility.

 

    Total     2012     2013     2014     2015     2016     Thereafter  
    ($ in millions)  

Contractual Obligations

           

Long-term debt(1)

  $ 669.8      $ —        $ —        $ —        $ 447.1      $ —        $ 222.7   

Operating leases

    8.6        0.8        2.8        2.2        1.4        1.0        0.4   

Capital lease obligations(2)

    52.5        0.4        1.1        1.2        1.4        1.6        46.8   

Unconditional purchase obligations(3)

    877.6        29.2        114.7        107.4        96.9        90.2        439.2   

Environmental liabilities(4)

    1.8        0.1        0.2        0.2        0.2        0.1        1.0   

Interest payments(5)

    186.4        16.2        24.2        64.5        44.9        24.2        12.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 1,796.7      $ 46.7      $ 143.0      $ 175.5      $ 591.9      $ 117.1      $ 722.5   

Other Commercial Commitments

             

Standby letters of credit(6)

  $ 27.2      $ —        $ —        $ —        $ —        $ —        $ —     

 

(1) We issued the Notes in an aggregate principal amount of $500.0 million on April 6, 2010. The First Lien Notes and Second Lien Notes bear an interest rate of 9.0% and 10.875% per year, respectively, payable semi-annually. The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. On October 23, 2012, we repurchased approximately $323.0 million of our First Lien Notes pursuant to a tender offer, and issued $500 million aggregate principal amount of 6.5% senior notes due 2022. We redeemed the remaining $124.1 million of outstanding First Lien Notes on November 23, 2012. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. In December 2010, we made a voluntary unscheduled prepayment on our First Lien Notes of $27.5 million. In May 2011, we repurchased $0.4 million of the First Lien Notes and $2.3 million of the Second Lien Notes. In December 2011 we issued an additional $200.0 million of First Lien Notes. As a result, the aggregate principal balance of the Notes is $669.8 million as of September 30, 2012, with $447.1 million (in respect of the First Lien Notes) due in 2015 and $222.7 million (in respect of the Second Lien Notes) due in 2017.
(2) The amount includes commitments under capital lease arrangements for equipment, and storage and terminal equipment of WEC.
(3)

The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville and (c) approximately $482.8 million payable ratably over ten years pursuant to petroleum transportation service agreements between our subsidiary, Coffeyville Resources Refining & Marketing (“CRRM”) and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM would receive transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011. The amount included in the table above represents the commitment based on the remaining term of the original ten-year

 

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agreements as of September 30, 2012. Effective November 1, 2012, the agreements were amended, extending the term from ten to twenty years, thereby significantly increasing the commitment with TransCanada.

(4) Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. See “Business—Environmental Matters.”
(5) Interest payments are based on stated interest rates for the respective Notes. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year.
(6) Standby letters of credit issued against the ABL credit facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil, $0.6 million issued to guarantee a portion of our insurance policy and $0.1 million issued for the purpose of providing support during the transition of letters of credit assumed during the Wynnewood Acquisition.

Our ability to make payments on and to refinance our indebtedness, to fund budgeted capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile. This, to a certain extent, is subject to refining spreads and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our New ABL Credit Facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2012.

Critical Accounting Policies

We prepare our combined financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited combined financial statements included elsewhere in this prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our combined financial statements.

Long-Lived Assets

We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we estimate what we believe are their reasonable useful lives. We account for impairment of long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment—Impairment or Disposal of Long-Lived Assets (“ASC 360”). In accordance with ASC 360, we review long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.

 

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Allocation of Costs

The combined financial statements included elsewhere in this prospectus have been prepared in accordance with SAB Topic 1-B, as more fully explained in Note 2 to our audited historical combined financial statements as of and for the years ended December 31, 2009, 2010 and 2011. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. CVR Energy has allocated general and administrative expenses to us based on allocation methodologies that management considers reasonable and result in an allocation of the cost of doing business borne by CVR Energy and Coffeyville Resources on our behalf; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Our historical combined Statements of Operations reflect all of the expenses that Coffeyville Resources and CVR Energy incurred on our behalf. Our combined financial statements therefore include certain expenses incurred by our parent which may include, but are not necessarily limited to, the following:

 

   

Officer and employee salaries and share-based compensation;

 

   

Rent or depreciation;

 

   

Advertising;

 

   

Accounting, tax, legal and information technology services;

 

   

Other selling, general and administrative expenses;

 

   

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

 

   

Financing costs, including interest, mark-to-market changes in interest rate swap, and losses on extinguishment of debt.

Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining based upon percentages determined by management to be reasonable and in line with the nature of an individual’s roles and responsibilities. See Note 17 (“Related Party Transactions”) to our audited historical combined financial statements as of and for the years ended December 31, 2009, 2010 and 2011 for further discussion of selling, general and administrative expenses incurred by CVR Energy and Coffeyville Resources and allocated to CVR Refining. Property insurance costs, included in direct operating expenses (exclusive of depreciation and amortization), were allocated based upon specific segment valuations. Allocations related to share-based compensation are determined in accordance with SAB Topic 1-B. See Note 17 (“Related Party Transactions”) for a detailed discussion of the basis for calculating the charges. If shared costs rise or the method by which shared costs are allocated changes, additional selling general and administrative expenses could be allocated to us, which could be material.

Derivative Instruments and Fair Value of Financial Instruments

We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long-term debt. Our derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging (“ASC 815”), and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. We recorded net gains (losses) from derivative instruments of $78.1 million, $(1.5) million and $(65.3) million in gain (loss) on derivatives, net for the fiscal years ended December 31, 2011, 2010 and 2009, respectively.

 

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Share-Based Compensation

We have been allocated non-cash share-based compensation expense from CVR Energy, Coffeyville Resources and Coffeyville Acquisition III LLC (“CALLC III”). CVR Energy, Coffeyville Resources and CALLC III account for share-based compensation in accordance with ASC 718 Compensation—Stock Compensation, or ASC 718, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. In accordance with ASC 718, CVR Energy, Coffeyville Resources and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. We recognize the costs of the share-based compensation incurred by CVR Energy, Coffeyville Resources and CALLC III on our behalf primarily in selling, general and administrative expenses (exclusive of depreciation and amortization), and a corresponding increase or decrease to divisional equity, as the costs are incurred on our behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees for acquiring, or in conjunction with selling goods or services, which require remeasurement at each reporting period through the performance commitment period, or in our case, through the vesting period. Costs are allocated by CVR Energy and Coffeyville Resources based upon the percentage of time a CVR Energy or Coffeyville Resources employee provides services to us. In the event an individual’s roles and responsibilities change with respect to services provided to us, a reassessment is performed to determine if the allocation percentages should be adjusted. In accordance with the services agreement that will be entered into in conjunction with the initial public offering, we will not be responsible for the payment of cash related to any share-based compensation allocated to us by CVR Energy or Coffeyville Resources.

Recent Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. The provisions of ASU 2011-04 are effective for interim and annual periods beginning after December 15, 2011. We adopted this ASU as of January 1, 2012. The adoption of this standard did not impact the condensed combined financial statement footnote disclosures.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U.S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for interim and annual periods beginning January 1, 2013. We believe this standard will expand our condensed combined financial statement footnote disclosures.

Quantitative and Qualitative Disclosures About Market Risk

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices. None of our market risk sensitive instruments are held for trading.

Commodity Price Risk

Our business has exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.

 

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We use a crude oil purchasing intermediary, Vitol, to purchase the majority of our non-gathered crude oil inventory for the Coffeyville refinery and, as of August 2012, our Wynnewood refinery, which allows us to take title to and price our crude oil at locations in close proximity to our refineries, as opposed to the crude oil origination point, reducing our risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods. In addition, we seek to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in our annual operating plan. Accordingly, we use commodity derivative contracts to economically hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard to our hedging activities, we may enter into, or have entered into, derivative instruments which serve to:

 

   

lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows;

 

   

hedge the value of inventories in excess of minimum required inventories; and

 

   

manage existing derivative positions related to change in anticipated operations and market conditions.

Further, we intend to engage only in risk mitigating activities directly related to our businesses.

The following table illustrates the number of barrels per day of production that we have hedged in each quarter of 2012 and 2013, and the weighted average price of all positions in respect of each such quarter:

 

Three Months Ending

   Hedged  barrels
(millions)
     Hedged crack  spread
($/barrel)
 

March 31, 2012

     2.9       $ 23.87   

June 30, 2012

     5.3       $ 26.67   

September 30, 2012

     5.0       $ 23.62   

December 31, 2012

     5.9       $ 23.50   

March 31, 2013

     6.5       $ 24.94   

June 30, 2013

     5.8       $ 27.18   

September 30, 2013

     5.6       $ 25.80   

December 31, 2013

     4.8       $ 26.88   

Basis Risk

The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure.

Examples of our basis risk exposure are as follows:

Time Basis—In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as a result of timing.

Location Basis—In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.

 

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Price and Basis Risk Management Activities

In the event our inventories exceed our target base level of inventories, we may enter into commodity derivative contracts to manage our price exposure to our inventory positions that are in excess of our base level. Excess inventories are typically the result of plant operations, such as a turnaround or other plant maintenance.

To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, we may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as specified in the swap) is different than the value contracted in the swap, then we will receive from or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of our margin. An example of our use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on Group 3 pricing.

From time to time, we also hold various NYMEX positions through a third party clearing house. On December 31, 2011, we had the following open commodity derivative contracts whose unrealized gains and losses were included in gain (loss) on derivatives in the Combined Statements of Operations. At December 31, 2011, we were net long 575 WTI crude oil contracts and short 375 heating oil contracts and 450 unleaded gasoline contracts. At December 31, 2011, our account balance maintained at the third party clearing house totaled approximately $4.0 million, of which $0.5 million is reflected on the Combined Balance Sheets in cash and cash equivalents and $3.8 million is reflected in other current assets. Our NYMEX positions were in an unrealized gain position of approximately $4.8 million as of December 31, 2011. This unrealized gain is reflected in the Combined Statement of Operations for the year ended December 31, 2011 and in other current assets in our Combined Balance Sheets at December 31, 2011. NYMEX transactions conducted throughout 2011 resulted in realized loss of approximately $7.4 million.

In addition, CVR Energy entered into several commodity swap contracts with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Combined Balance Sheets with changes in fair value currently recognized in the Combined Statements of Operations. At September 30, 2012, we had over-the-counter commodity swaps consisting of 26.3 million barrels of crack spreads primarily to fix the margin on a portion of future gasoline and distillate production from our two refineries. The fair value of the outstanding contracts at September 30, 2012 was a net unrealized loss of $115.7 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of the commodity hedging instruments of $26.3 million.

 

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INDUSTRY

Oil Refining

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 crude oil and other feedstocks and operating expenses, and to do so without compromising safety and environmental performance. According to 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 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 smaller and less efficient refineries that had limited access to a wide variety of crude oils or were unable to profitably process feedstock into a marketable product mix were closed.

Operating Refineries & Utilization

 

LOGO

 

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Regional Market

Refining capacity

Supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a given refinery’s location. Our two refineries operate in the southwestern portion of the PADD II region known as Group 3. According to EIA data, 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 combined capacity from our refineries constitutes approximately 22% of the refining capacity of Group 3 of the PADD II region. The table below summarizes the currently operational refineries in the region where we operate:

 

Refinery location

  

Company

   Crude Capacity (thousand  bpd)
As of January 1, 2012
     Complexity  

Ponca City, OK

   Phillips66      198.4         9.8   

El Dorado, KS

   HollyFrontier      138.0         12.5   

Tulsa, OK

   HollyFrontier      155.3         14.0   

Coffeyville, KS

   CVR Refining      115.0         12.9   

Ardmore, OK

   Valero      85.0         12.0   

McPherson, KS

   NCRA      85.5         N/A   

Wynnewood, OK

   CVR Refining      70.0         9.3   
     

 

 

    

Total:

        847.2      
     

 

 

    

Source: Competitor crude capacity data from EIA; competitor complexity from publicly available information.

The map below depicts PADD II (including the Group 3 region), as well as PADD III:

 

LOGO

 

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Products

According to the EIA, total demand for refined products in Group 3 of the PADD II region was over 330 million barrels in 2011. The current operational refining capacity in Group 3 is insufficient to meet this demand. 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 in 2011. The refined product volumes that are necessary to satisfy the demand in excess of Group 3 production are primarily sourced from suppliers located outside of the PADD II region, in particular from the Gulf Coast. The shortage of refining capacity is a factor that results in local refiners realizing higher margins on average on these products as compared to those suppliers who have to transport their products to this region over longer distances and as a result incur additional costs. The table below illustrates the supply deficit relative to the available local refining capacity for gasoline and distillates in our key supply area (Kansas, Oklahoma, Missouri, Nebraska and Iowa):

 

    Annual Refined Fuels Supplier Sales vs Refinery Production  
    (Thousand barrels)  
    2007     2008     2009     2010     2011  

Gasoline Annual Sales

    565        549        543        559        545   

Distillate Annual Sales

    354        360        328        367        362   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Annual Sales

    919        909        871        926        907   

Refinery Gasoline and Distillate Production

    695        746        757        783        784   

Demand in Excess of Refinery Production

    224        163        114        144        123   

Percentage of Total Annual Sales

    24     18     13     15     14
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Source: EIA

These favorable supply-demand dynamics for gasoline and distillate have resulted in a premium of approximately $1.54 per barrel over the five year period ended December 31, 2011 for the PADD II Group 3 2-1-1 benchmark crack spread over NYMEX 2-1-1.

 

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Crude oil

The map below summarizes the key oil plays and major pipeline infrastructure that currently impacts our refining operations:

 

LOGO

 

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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 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.

Western Canada Crude Oil Forecasts

LOGO

Note: Oil sands includes upgraded conventional, imported condensate, manufactured diluent from upgraders and upgraded heavy volumes coming from upgraders

Source: Canadian Association of Petroleum Producers, “Crude Oil Forecast, Markets & Pipelines, June 2012”

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.

Regional Play Oil & NGL Forecasts

LOGO

Note: Anadarko Basin includes Mississippi Lime, Granite Wash, Cleveland Tonkawa, Marmaton; DJ Niobrara includes horizontal wells only.

Source: Investment Technology Group

 

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Since the beginning of 2011, WTI crude has priced at a considerable discount to the price of 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 a result of ever-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 differentials of WTI as compared to Brent, WTI to Mars, WCS to WTI, WTS to WTI, and 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.

 

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BUSINESS

Overview

We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the mid-continent region. We are a petroleum refiner and 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 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 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 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 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. 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

 

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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.

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 Wynnewood refinery via two separate third-party pipelines 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.

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 period 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 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 on 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

 

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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. We 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 upgrading 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 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 of our turnaround 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. 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 of experience in refining and petrochemicals in areas relating to crude, feedstocks, product and process optimization, commercial activities, acquisitions and capital utilization.

 

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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. The primary components of our business strategy are to:

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 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, the New ABL Credit Facility, and the $150 million intercompany credit facility with Coffeyville Resources that we expect to enter into. 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 to 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 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

 

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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 the Vitol Agreement, 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.

Our History

Prior to March 3, 2004, our Coffeyville refining business was operated as a small component of Farmland Industries, Inc. (“Farmland”) an agricultural cooperative. Farmland filed for bankruptcy protection on May 31, 2002. Coffeyville Resources, a subsidiary of Coffeyville Group Holdings, LLC, won the bankruptcy court auction for Farmland’s Coffeyville refinery and related business (as well as the adjacent nitrogen fertilizer plant now operated by CVR Partners) and completed the purchase of these assets on March 3, 2004.

On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, all of the subsidiaries of Coffeyville Group Holdings, LLC, including our Coffeyville refinery and related businesses (as well as the adjacent nitrogen fertilizer plant now operated by CVR Partners), were acquired by Coffeyville Acquisition LLC (“CALLC”), a newly formed entity principally owned by funds affiliated with Goldman, Sachs & Co. and Kelso & Company.

On October 26, 2007, CVR Energy completed its initial public offering and its common stock was listed on the NewYork Stock Exchange under the symbol “CVI.” CVR Energy was formed as a wholly-owned subsidiary of CALLC in September 2006 in order to complete the initial public offering of the businesses acquired by CALLC. At the time of its initial public offering, CVR Energy operated our business and indirectly owned all of the limited partner interests in CVR Partners. In April 2011, CVR Partners completed its initial public offering. CVR Partners’ common units were listed on the New York Stock Exchange under the symbol “UAN.”

On December 15, 2011, Coffeyville Resources acquired all of the issued and outstanding shares of WEC for $593.4 million, consisting of an initial cash payment of $525.0 million, capital expenditure adjustments of $1.8 million and $66.6 million for working capital. The assets acquired included a 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of storage tanks.

In May 2012, affiliates of Icahn Enterprises acquired a majority of the common stock of CVR Energy. Icahn Enterprises’ aggregate ownership in CVR Energy as of September 30, 2012 was 71,198,718 shares of common stock, or approximately 82% of the outstanding common stock.

We were formed by CVR Energy in September 2012 in order to own and operate petroleum and auxiliary businesses as a limited partnership. As part of the Transactions occurring in connection with this offering, Coffeyville Resources contributed its wholly-owned subsidiaries and logistics assets described above in “—Overview” to CVR Refining, LLC in October 2012, and CVR Refining Holdings, a subsidiary of Coffeyville Resources, contributed CVR Refining, LLC to us in December 2012. Following the Transactions, CVR Refining Holdings will own common units as well as CVR Refining GP, our general partner.

Our Assets

Our Coffeyville refinery is situated on approximately 440 acres in southeast Kansas, approximately 100 miles northeast of Cushing, Oklahoma, a major crude oil trading and storage hub. Our Wynnewood refinery is situated on approximately 400 acres located approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles southwest of Cushing.

 

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For the year ended December 31, 2011, our Coffeyville refinery’s product yield included gasoline (mainly regular unleaded) (44%), ULSD (42%), and pet coke and other refined products such as natural gas liquids (“NGLs”) (including propane and butane), slurry, sulfur and gas oil (14%). Our Wynnewood refinery’s product yield included gasoline (54%), ULSD (34%), asphalt (6%), and other products (6%) (slurry, sulfur and gas oil, and specialty products such as propylene and solvents).

Our business also includes the following auxiliary operating assets:

 

   

Crude Oil Gathering System. We own and operate a crude oil gathering system serving Kansas, Oklahoma, western Missouri, southwestern Nebraska and Texas. The system has field offices in Bartlesville, Oklahoma, Plainville, Kansas and Winfield, Kansas. The system is comprised of approximately 350 miles of feeder and trunk pipelines, over 125 crude oil transports, and associated storage facilities for gathering crude oils purchased from independent crude oil producers in our gathering area. We also lease a section of a pipeline from Magellan, which is incorporated into our crude oil gathering system. Our crude oil gathering system has a gathering capacity of approximately 50,000 bpd. Gathered crude oil provides an attractive and competitive base supply of crude oil for our Coffeyville refinery.

 

   

Pipelines and Storage Tanks. We own a proprietary pipeline system capable of transporting approximately 145,000 bpd of crude oil from our Broome Station tank farm located near Caney, Kansas to our Coffeyville refinery. Crude oils sourced outside of our proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to our Broome Station tank farm via a pipeline owned by Plains Pipeline L.P. (“Plains”). We also control associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our Coffeyville refinery, 0.5 million barrels of crude oil storage at Wynnewood, Oklahoma, 1.0 million barrels in Cushing, Oklahoma and lease an additional 3.3 million barrels of storage capacity located at Cushing. In addition to crude oil storage, we own approximately 4.5 million barrels of combined refinery related storage capacity.

Crude and Feedstock Supply

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

Our Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery’s crude oil has been acquired domestically, mainly from Texas and Oklahoma.

Crude oil is supplied to our Coffeyville refinery through our wholly-owned gathering system and by pipeline. We have continued to increase the number of barrels of crude oil supplied through our crude oil gathering system in 2011 and it now has the capacity of supplying approximately 50,000 bpd of crude oil to our refineries. In the year ended December 31, 2011, the gathering system supplied approximately 35% of the Coffeyville refinery’s crude oil demand. Locally produced crude oils are delivered to our refineries at a discount to WTI, and although slightly heavier and more sour, offer good economics to our refineries. These crude oils are light and sweet enough to allow us to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining our target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of our proprietary gathering system are delivered to Cushing, Oklahoma by various pipelines, including the Basin, Keystone and Spearhead pipelines, and subsequently to our Broome Station tank farm via the Plains pipeline. From the Broome Station tank farm,

 

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crude oil is delivered to our Coffeyville refinery via our own 145,000 bpd pipeline system. Crude oils are delivered to the Wynnewood refinery by two separate pipelines, and received into storage tanks at terminals located at or near the refinery.

For the year ended December 31, 2011, Coffeyville’s crude oil supply blend was comprised of approximately 80% light sweet crude oil, 2% light/medium sour crude oil and 18% heavy sour crude oil. For the year ended December 31, 2011, Wynnewood’s crude oil supply blend was comprised of approximately 88% sweet crude oil and 12% light/medium sour crude oil. The light sweet crude oil supply blend includes our locally gathered crude oil.

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

The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up into North Dakota.

Crude Oil Supply Agreement

In August 2012, we and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between us and Vitol dated March 30, 2011, as amended. The March 2011 agreement replaced the previous supply agreement between us and Vitol dated December 2, 2008, as amended, which was terminated by Vitol and us on March 30, 2011.

The Vitol Agreement provides that we will obtain substantially all of the crude oil for our Coffeyville and Wynnewood refineries through Vitol, other than the crude oil gathered by us. We and Vitol will work together to identify crude oil and pricing terms that meet our crude oil requirements. We or Vitol will negotiate the costs of each barrel of crude oil that is purchased from third-party crude oil suppliers. Vitol purchases all such crude oil, executes all third-party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to us. Title and risk of loss for all crude oil purchased by us through the Vitol Agreement passes to us upon delivery to one of three delivery points described in the Vitol Agreement. We pay Vitol a fixed origination fee per barrel plus the negotiated cost (including logistics costs) of each barrel purchased.

The Vitol Agreement has an initial term commencing August 31, 2012 and extending through December 31, 2014. Following the initial term, the Vitol Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the initial Term or any renewal term. Notwithstanding the foregoing, we have an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

 

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Refining Process

Coffeyville Refinery. Our Coffeyville refinery is a 115,000 bpd facility with operations including fractionation, catalytic cracking, hydrotreating, reforming, coking, isomerization, alkylation, sulfur recovery and propane and butane recovery. Our Coffeyville refinery benefits from significant refining unit redundancies, which include two crude oil distillation and vacuum towers, three sulfur recovery units and four hydrotreating units. These redundancies allow us to continue to receive and process crude oil even if one tower requires unplanned maintenance without having to shut down the entire refinery in the case of a major unit turnaround. In addition, our Coffeyville refinery has a redundant supply of hydrogen pursuant to our feedstock and shared services agreement with CVR Partners. During the nine months ended September 30, 2012, our Coffeyville refinery processed approximately 111,505 bpd of crude oil and 6,448 bpd of feedstocks and blendstocks. These throughput rates for the first nine months of 2012 reflect the effect of Crude Unit #2 being down for turnaround for 24 days during the first quarter of 2012. Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil into products such as gasoline, diesel, kerosene, propane, butane, sulfur, heavy oil and petroleum coke. Below is a simplified process flow chart of the major refining units:

 

LOGO

 

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The following table summarizes our Coffeyville refinery’s major refining unit capacities. Unit capacities are shown in thousand barrels per stream day, unless otherwise indicated.

 

Unit Name

   Capacity
(MBPSD unless  otherwise
indicated)
 

Crude Unit #1

     70.0   

Crude Unit #2

     50.0   

Vacuum Unit #2

     16.5   

Vacuum Unit #3

     29.5   

Coker

     25.0   

FCC Unit

     36.0   

ULSG Unit

     22.0   

Alkylation Unit

     10.0   

Naphtha Hydrotreater

     36.0   

Naphtha Splitter

     38.0   

Isomerization Unit

     8.5   

Continuous Catalyst Regeneration (CCR) Reformer Unit

     26.0   

Hydrogen PSA Unit, mmscf/d

     26.0   

HDS Condensate Splitter

     5.0   

Kerosene Hydrotreater

     9.0   

Diesel Hydrotreater #1

     30.0   

Diesel Hydrotreater #2

     27.0   

Sulfur Unit #1 long tons/day

     20.0   

Sulfur Unit #2 with Tail Gas Unit, long tons/day

     35.0   

Sulfur Unit #3 with Tail Gas Unit, long tons/day

     75.0   

Wynnewood Refinery. Our Wynnewood refinery is a 70,000 bpd facility with operations including fractionation, cracking, hydrotreating, hydrocracking, reforming, solvent deasphalting, alkylation, sulfur recovery and propane and butane recovery. Similar to our Coffeyville refinery, our Wynnewood refinery benefits from unit redundancies, including two crude oil distillation and vacuum towers and four hydrotreating units. Our Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil (although isobutane, gasoline components, and normal butane are also typically used) into products such as gasoline, jet fuel, including Jet A and military jet (“JP8”), kerosene, propane, butane, propylene, sulfur, solvents, heavy oil and asphalt. During the nine months ended September 30, 2012, our Wynnewood refinery processed approximately 65,084 bpd and 3,000 bpd of crude oil and feedstocks and blendstocks, respectively. Below is a simplified process flow chart of the major refining units at our Wynnewood refinery.

 

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LOGO

The following table summarizes our Wynnewood refinery’s major process unit capacities. Unit capacities are shown in thousand barrels per stream day, unless otherwise indicated.

 

Unit Name

   Capacity
(MBPSD unless  otherwise
indicated)
 

No. 1 Crude Unit

     35.0   

No. 2 Crude Unit

     35.0   

Vacuum Unit

     15.0   

No. 2 Vacuum Unit

     27.0   

FCC Unit

     20.5   

Hydrocracker/Hydrotreater

     15.0   

Hydrofluoric Acid Alkylation Unit

     5.5   

Continuous Catalyst Regeneration (CCR) Reformer Unit

     18.5   

Naphtha Hydrotreater

     12.5   

Distillate Hydrotreater

     20.0   

ROSE Unit

     4.4   

Prime G

     13.0   

Light Straight Run (LSR) Hydrotreater

     4.4   

Propylene Splitter Unit

     6.5   

Fuel Gas Treater Unit (million standard cubic feet/day)

     10.0   

Sulfur Recovery Unit (long tons/day)

     50.0   

Sulfur Recovery Unit (TKI) (long tons/day)(1)

     60.0   

 

(1) We expect this unit will be in place following the fourth quarter 2012 turnaround.

 

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Distribution and Marketing

We focus our Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity to the refinery and their pipeline access, and we also have access to the Rocky Mountain area. We engage in rack marketing, which is the supply of product through tanker trucks directly to customers located in close geographic proximity to our Coffeyville refinery and to customers located at throughput terminals on Magellan’s and NuStar’s refined products distribution systems. For the year ended December 31, 2011, approximately 35% of the Coffeyville refinery’s products were sold through the rack system directly to retail and wholesale customers while the remaining 65% was sold through pipelines via bulk spot and term contracts. We make bulk sales (sales into third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.

The Wynnewood refinery ships its finished product via pipeline, rail car, and truck. Approximately 60% of the Wynnewood refinery’s finished products are distributed in Oklahoma. Non-Oklahoma gasoline and ultra-low sulfur diesel volumes are distributed throughout the mid-continent region via the Magellan Pipeline. Wynnewood distributes approximately 12,000 bpd of gasoline and ultra-low sulfur diesel via the refinery’s truck rack, and has the ability to distribute volumes via the NuStar pipeline system to South Dakota, Nebraska, Iowa, and Kansas. Wynnewood also sells jet fuel to the U.S. Department of Defense via the truck rack. In addition, Wynnewood maintains exchange agreements with five refineries in nearby states.

Customers

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

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

Competition

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

 

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Seasonality

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

Environmental Matters

Our businesses are subject to extensive and frequently changing federal, state and local, environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, the storage, handling, use and transportation of petroleum products, and the characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact our business and operations by imposing:

 

   

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

 

   

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

 

   

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

 

   

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

Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimate impact on our business of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.

Environmental health and safety is our top priority, as demonstrated by the fact that approximately 20% of annual cash incentive compensation is tied to the satisfaction of safety performance goals at our refineries and logistics operations. See “Compensation Discussion and Analysis—Compensation Objectives—Elements of the Compensation Program—Annual Bonus.”

The principal environmental risks associated with our businesses are outlined below.

The Federal Clean Air Act

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

 

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

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

On September 12, 2012, the EPA published in the Federal Register final revisions to its New Source Performance Standards for process heaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the effective date of the regulation was stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissions of sulfur dioxide from flares, as well as require certain work practice and monitoring standards for flares. We are reviewing the rule and expect to make any required capital expenditure to comply with the new requirements. We do not believe that the costs of complying with the rule will be material.

On August 14, 2012, the EPA sent both the Wynnewood and Coffeyville refineries letters regarding the EPA’s recently issued enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations and the EPA’s related effort to conduct compliance evaluations and, where warranted, bring enforcement actions against petroleum refining companies that operate flares that are in noncompliance. Because the EPA has not specifically told us that our operations are in non-compliance, we cannot currently predict whether we may have to incur costs related to this EPA initiative.

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

In March 2012, CRRM entered into a Second Consent Decree with the EPA, which replaces the 2004 Consent Decree (other than the clean up obligations). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a “global settlement” under the EPA’s “National Petroleum Refining Initiative.” Under the National Petroleum Refining Initiative, the EPA identified industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into “global settlements” pertaining to all “marquee” issues. Under the Second Consent Decree, CRRM was required to pay a civil penalty of approximately $0.7 million and is required to complete the installation of FCCU controls required under the 2004 Consent Decree, the remaining costs of which are expected to be approximately $49.0 million, of which approximately $47.0 million is expected

 

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to be capital expenditures and complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree would not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012.

WRC has not entered into a global settlement with the EPA and the ODEQ under the National Petroleum Refining Initiative, although it had discussions with the EPA and ODEQ about doing so. Instead, WRC entered into the Wynnewood Consent Order with ODEQ in August 2011. The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The costs of complying with the Wynnewood Consent Order, other than costs associated with a scheduled turnaround, are not expected to be material. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for the matters described in the ODEQ order. Recently, ODEQ proposed assessing a $20,000 penalty against WRC for air releases that, according to the purchase and sale agreement, were covered by the Wynnewood Consent Order. We have outlined our position with ODEQ that the air releases, and any similar releases that may occur in the future until additional controls are installed in the refinery flares per the Wynnewood Consent Order, are released by the Wynnewood Consent Order. We await ODEQ’s response.

In August 2012, Wynnewood received a letter from ODEQ alleging certain potential air quality emission violations. Wynnewood responded in September 2012 that it is not subject to any penalties for these alleged violations because they are covered by the Wynnewood Consent Order. Wynnewood hopes to settle these alleged violations, but there can be no assurance that the matter will settle and if it does not, Wynnewood will contest the alleged violations.

On September 23, 2011, the United States Department of Justice (“DOJ”), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (“RMP”) (in addition to other matters described below, see “—Environmental Remediation”). CRRM has reached an agreement with the DOJ to resolve the DOJ’s claims. The agreement is memorialized in a Consent Decree that CRRM has signed and returned to DOJ and is awaiting DOJ’s signature. Once signed by DOJ, the Consent Decree will be filed with the court and, if approved, entered by the Court. CRRM will pay civil penalties in excess of $100,000; however, CRRM does not anticipate that civil penalties or any other costs associated with the settlement will be material. The lawsuit is temporarily stayed while the parties finalize their agreement.

The Coffeyville refinery’s Clean Air Act Title V operating permit has expired, and has not yet been re-issued. The refinery submitted an application for renewal and currently operates under a permit shield, which authorizes permittees who timely submit their renewal application, to continue operations until the permit is re-issued. The permit renewal process has begun, and capital costs or expenses, if any, related to changes to this permit are not known yet, but are not expected to be material.

The Federal Clean Water Act

The federal Clean Water Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect our operations. Direct impacts occur through the federal Clean Water Act’s permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load (“TMDL”) of pollutants that may be released to a particular water body based on its use. In addition, water resources are

 

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becoming and in the future may become scarcer, and many refiners, including CRRM and WRC, are subject to restrictions on their ability to use water in the event of low availability conditions. Both CRRM and WRC have contracts in place to receive additional water during low-flow conditions, but these conditions could change over time if water becomes scarce.

The Wynnewood refinery’s Clean Water Act permit (“OPDES permit”) has expired and we are in the public comment period of the re-issuance by ODEQ. The refinery currently operates under a permit shield, which authorizes permittees who timely submit their renewal application to continue discharging under an expired permit until the ODEQ re-issues the permit. ODEQ has proposed modifications to Oklahoma’s Water Quality Management Plan for the Wynnewood refinery, which are pending EPA approval. Similarly, the Coffeyville refinery’s Clean Water Act permit has also expired and has not yet been re-issued. Capital costs or expenses related to changes to these permits are not expected to be material.

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

Release Reporting

Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”) and the RMP. If we fail to timely or properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.

The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws.

Fuel Regulations

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

Tier III. The EPA is expected to propose “Tier 3” gasoline sulfur standards in 2013. If the EPA were to propose a standard at the level recently being discussed in the pre-proposal phase by the EPA, CRRM will need to make modifications to its equipment in order to meet the anticipated new standard. If the Tier 3 regulations are eventually implemented and lower the maximum allowable content of sulfur or other constituents in fuels that we produce, we may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs to comply with the new standards. It is not anticipated that the

 

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Wynnewood refinery will require additional capital to meet the anticipated new standard. We believe that costs associated with the EPA’s proposed Tier 3 rule will not be material.

Mobile Source Air Toxic II Emissions. In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC were each considered to be “small refiners” under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, due to the change of control in CVR Energy in May 2012, the MSATII projects have been accelerated by three months due to the loss of “small refiner” status. Capital expenditures to comply with the rule are expected to be approximately $59 million for CRRM and $78 million for WRC.

Renewable Fuel Standards. In 2007, the EPA promulgated the Renewable Fuel Standard (“RFS”), which requires refiners to blend “renewable fuels” in with their transportation fuels or purchase renewable energy credits, known as renewable identification numbers (“RINs”) in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 of the prior year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2012, about 9% of all fuel used was required to be “renewable fuel.” The EPA has not yet proposed the renewable fuel percentage standards for 2013. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. To achieve compliance with the renewable fuel standard for the remainder of 2012, CRRM is able to blend a small amount of ethanol into gasoline sold at its refinery loading rack, but otherwise will have to purchase RINs to comply with the rule. CRRM requested “hardship relief” (an extension of the compliance deadline) from the EPA based on the disproportionate economic impact of the rule on CRRM, but the EPA denied CRRM’s request on February 17, 2012.

WRC’s refinery is a small refinery under the RFS and has received a two year extension of time to comply. Therefore, WRC will have to begin complying with the RFS beginning in 2013 unless a further extension is requested and granted.

Greenhouse Gas Emissions

Various regulatory and legislative measures to address greenhouse gas emissions (including carbon dioxide (“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 authority granted to it under the federal Clean Air Act

In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our greenhouse gas emissions at our Coffeyville and Wynnewood refineries and are reporting the emissions to the EPA. 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 the Prevention of Significant Deterioration (“PSD”) and Title V programs of the federal Clean Air Act. 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”) for its greenhouse gas emissions. Phase-in permit requirements began for the largest stationary sources in 2011.

In the meantime, 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

 

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emissions from petroleum refineries. The EPA may propose the NSPS in 2013. It is not known whether the proposed rule would affect both new and existing petroleum refineries, or just new petroleum refineries. 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 Midwestern 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 regulations 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 current or 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 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.

RCRA

Our operations are subject to the RCRA requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances.

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

Impacts of Past Manufacturing. The 2004 Consent Decree that CRRM signed with the EPA and KDHE required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which require investigation or remediation projects. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. Remediation at both sites, if necessary, will be based on the results of the investigations. The Wynnewood refinery operates under a RCRA permit. A RCRA facility investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, the ODEQ has

 

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required further investigations of groundwater conditions. Remediation, if necessary, will be based upon the results of further investigation.

The anticipated investigation and remediation costs through 2015 were estimated, as of December 31, 2011, to be as follows:

 

Facility

   Site
Investigation
Costs
     Capital Costs      Total Operation
& Maintenance
Costs through
2015
     Total Estimated
Costs through
2015
 
     (in millions)  

Coffeyville Refinery

   $ 0.6         —         $ 0.7       $ 1.3   

Phillipsburg Terminal

     0.4         —           0.9         1.3   

Wynnewood Refinery

     0.3         —           0.4         0.7   

Total Estimated Costs

   $ 1.3         —         $ 2.0       $ 3.3   

These estimates are based on current information and could go up or down as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2012, we will spend $4.0 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $2.4 million in 2011 associated with related remediation.

Financial Assurance. We are required under the 2004 Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010 agreement between CRRM, CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $5.0 million for clean-up obligations at the Phillipsburg terminal and additional self-funded financial assurance of approximately $1.7 million and $2.1 million for clean-up obligations at the Coffeyville refinery and Phillipsburg terminal, respectively. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.3 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.

Environmental Remediation

Under CERCLA, RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the Oil Pollution Act of 1990 (“OPA”) generally subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States. On September 23, 2011, the DOJ, acting on behalf of the EPA and the Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking (i) recovery from CRRM of EPA’s oversight costs under the OPA, (ii) a civil penalty under the Clean Water Act (as amended by the OPA) and (iii) recovery from CRRM related to alleged non-compliance with the RMP. (See “—The Federal Clean Air Act” above.) DOJ’s OPA and ONA claims are related to the 2007 flood and oil spill. CRRM has reached an agreement with DOJ to resolve DOJ’s claims. Civil penalties associated with the proceeding will exceed $100,000; however, CRRM does not anticipate that civil penalties or any other costs associated with the proceeding will be material. The lawsuit is temporarily stayed while the parties finalize the Consent Decree.

 

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As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material.

Environmental Insurance

We are covered by CVR Energy’s premises pollution liability insurance policies with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $5.0 million. The policies include business interruption coverage, subject to a 10-day waiting period deductible. This insurance expires on July 1, 2013. The policies insure specific covered locations. The policies insure (i) claims, remediation costs, and associated legal defense expenses for pollution conditions at, or migrating from, a covered location, and (ii) the transportation risks associated with moving waste from a covered location to any location for unloading or depositing waste. The policies cover any claim made during the policy period as long as the pollution conditions giving rise to the claim commenced on or after March 3, 2004. The premises pollution liability policies contain exclusions, conditions, and limitations that could apply to a particular pollution condition claim, and there can be no assurance such claim will be adequately insured for all potential damages.

In addition to the premises pollution liability insurance policies, we benefit from casualty insurance policies maintained by CVR Energy having an aggregate and occurrence limit of $150.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. Coverage under the casualty insurance policies for pollution does not apply to damages at or within our insured premises. The pollution coverage provided in the casualty insurance policies contains exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.

Safety, Health and Security Matters

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

The Wynnewood refinery has been the subject of a number of federal Occupational Safety and Health Act (“OSHA”) inspections since 2006. As a result of these inspections, the Wynnewood refinery entered into four OSHA settlement agreements in 2008, pursuant to which it agreed to undertake certain studies, conduct abatement activities, and revise and enhance certain OSHA compliance programs. The costs associated with these studies, abatement activities and program revisions are not expected to exceed $1.0 million once the October 2012 turnaround is complete.

Process Safety Management. We maintain a process safety management (“PSM”) program. This program is designed to address all aspects of the OSHA guidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and we continue to make improvements in our management systems as well as our operations.

Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.

 

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Employees

As of September 30, 2012, we employed approximately 800 people. These employees are covered by health insurance, disability and retirement plans established by CVR Energy. We believe that our relationship with our employees is good.

As of September 30, 2012, the Coffeyville refinery employed approximately 540 of our employees, about 59% of whom were covered by a collective bargaining agreement. These employees are affiliated with six unions of the Metal Trades Council of the AFL-CIO (“Metal Trade Unions”) and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC (“United Steelworkers”). A new collective bargaining agreement, which covers union members who work directly at the Coffeyville refinery, was entered into with the Metal Trade Unions effective August 31, 2008 and is effective through March 2013. No substantial changes were made to the prior agreement. In addition, a new collective bargaining agreement, which covers CVR Energy’s unionized employees who work in the terminalling and related operations, was entered into with the United Steelworkers in March 2012. The United Steelworkers collective bargaining agreement 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. There were no substantial changes to the prior agreement.

As of September 30, 2012, the Wynnewood refinery employed approximately 270 people, about 63% of whom were represented by the International Union of Operating Engineers. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2015.

Following the closing of this offering, we will also rely on the services of employees of CVR Energy in the operation of our business pursuant to a services agreement among us, CVR Energy and our general partner. Following the closing of this offering, CVR Energy will provide us with the following services under the agreement, among others:

 

   

services from CVR Energy’s employees in capacities equivalent to the capacities of corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve us on a shared, part-time basis only, unless we and CVR Energy agree otherwise;

 

   

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

 

   

management of our property and the property of our subsidiaries in the ordinary course of business;

 

   

recommendations on capital raising activities, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions;

 

   

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

 

   

recommending the payment of distributions; and managing or providing advice for other projects as may be agreed by CVR Energy and our general partner from time to time.

For more information on this services agreement, see “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners.”

 

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Properties

We own two facilities, our Coffeyville refinery, which is located in Coffeyville, Kansas, and our Wynnewood refinery, located in Wynnewood, Oklahoma. Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas, where a number of our senior executives work. We also have an administrative office in Kansas City, Kansas, where other of our senior executives work. The offices in Sugar Land and Kansas City are leased by CVR Energy (the leases expire in 2017 and 2015, respectively) and we will pay a pro rata share of the rent on those offices. We believe that our facilities, together with CVR Energy’s leased facilities, are sufficient for our needs.

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

Legal Proceedings

We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under “—Environmental Matters.” We also incorporate by reference the information regarding the lawsuits and proceedings described and referenced in Note 14, “Commitments and Contingencies” to our unaudited combined financial statements contained elsewhere in this prospectus. In accordance with U.S. GAAP, we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

 

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MANAGEMENT

Management of CVR Refining, LP

Our general partner, CVR Refining GP, manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Our general partner will be owned by CVR Refining Holdings, a wholly-owned indirect subsidiary of CVR Energy. The operations of our general partner in its capacity as general partner are managed by its board of directors. Actions by our general partner that are made 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. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The officers of our general partner will manage the day-to-day affairs of our business.

Limited partners will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions which replace default fiduciary duties with contractual corporate governance standards. See “The Partnership Agreement.” Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

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 consist of a majority of independent directors, may choose to not have a compensation committee or have a compensation committee that does not consist entirely of independent directors, and 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.

Upon completion of this offering, we expect that the board of directors of our general partner will consist of eleven directors.

The board of directors of our general partner will establish an audit committee consisting of members who meet the independence and experience standards established by the NYSE and the Exchange Act. We expect that the audit committee will initially consist of Glenn R. Zander, Jon R. Whitney and Kenneth Shea. The audit committee’s responsibilities are to review our accounting and auditing principles and procedures, accounting functions and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent accountants; to review with the independent accountants the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters. NYSE regulations and applicable laws require that our general partner have an audit committee consisting of at least one independent director prior to the units being listed; at least two independent directors within 90 days of the effective date of this prospectus; and at least three independent directors not later than one year following the effective date of this prospectus.

 

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In addition, the board of directors of our general partner will establish a conflicts committee consisting entirely of independent directors. We expect that the conflicts committee will initially consist of Glenn R. Zander, Jon R. Whitney and Kenneth Shea. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other. The conflicts committee may then determine whether the resolution of the conflict of interest is adverse to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders.

Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership. Decisions by our general partner that are made in its individual capacity will be made by CVR Refining Holdings, the sole member of our general partner, not by the board of directors of our general partner.

Executive Officers and Directors

The following table sets forth the names, positions and ages (as of September 30, 2012) of the executive officers and directors of our general partner.

Certain of the executive officers of our general partner are also executive officers of CVR Energy and CVR Partners’ general partner, and are providing their services to our general partner and us pursuant to the services agreement to be entered into among us, CVR Energy and our general partner. The executive officers listed below will divide their working time between the management of CVR Energy and us. We estimate that our executive officers will spend the following percentage of their working time managing us for the first year following this offering: John J. Lipinski (55%), Stanley A. Riemann (50%), Susan M. Ball (45%), Edmund S. Gross (40%), Robert W. Haugen (100%), Wyatt E. Jernigan (100%), Christopher G. Swanberg (60%) and David L. Landreth (100%).

 

Name

   Age
(as of  09/30/2012)
  

Position With Our General Partner

John J. Lipinski

   61    Chief Executive Officer and President, Director

Stanley A. Riemann

   61    Chief Operating Officer, Director

Susan M. Ball

   49    Chief Financial Officer and Treasurer

Edmund S. Gross

   61    Senior Vice President, General Counsel and Secretary

Robert W. Haugen

   54    Executive Vice President, Refining Operations

Wyatt E. Jernigan

   61    Executive Vice President, Crude Oil Acquisition and Petroleum Marketing

Christopher G. Swanberg

   54    Vice President, Environmental, Health and Safety

David L. Landreth

   56    Vice President, Economics and Planning

Carl C. Icahn

   76    Director nominee

Vincent J. Intrieri

   56    Director

Daniel A. Ninivaggi

   48    Director nominee

SungHwan Cho

   38    Director nominee

Samuel Merksamer

   32    Director

Glenn R. Zander

   65    Director nominee

Jon R. Whitney

   68    Director nominee

Keith Cozza

   34    Director nominee

Kenneth Shea

   54    Director nominee

 

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John J. Lipinski has served as the Chief Executive Officer and President of our general partner, as well as director on the board of directors of our general partner, since our inception in September 2012. In addition, he has served as CVR Energy’s Chief Executive Officer and President and as a member of its board of directors since September 2006, and previously served as the Chairman of its board of directors from April 2009 until May 2012. In addition, Mr. Lipinski has served as Executive Chairman of the board of directors of the general partner of CVR Partners since June 2011 and, prior to assuming such role, served as Chief Executive Officer, President and a director of CVR Partners’ general partner beginning in October 2007 and as Chairman of the board of directors of CVR Partners’ general partner beginning in November 2010. Mr. Lipinski has over 40 years of experience in the petroleum refining industry. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation, eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation’s refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen-based chemical processing and lubricant operations, as well as the corporate engineering and construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a managing director and partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski graduated from Stevens Institute of Technology with a bachelor’s degree in Engineering (chemical) and received a Juris Doctor degree from Rutgers University School of Law. Mr. Lipinski’s over 40 years of experience in the petroleum refining industry adds significant value to the board of directors of our general partner, and his in-depth knowledge of the issues, opportunities and challenges facing us provides the direction and focus the board needs to ensure the most critical matters are addressed.

Stanley A. Riemann has served as Chief Operating Officer of our general partner since our inception in September 2012. Mr. Riemann has also served as Chief Operating Officer of CVR Energy since September 2006 and Chief Operating Officer of Coffeyville Resources since February 2004. In addition, since October 2007, Mr. Riemann has served as the Chief Operating Officer of the general partner of CVR Partners, and since June 2011 he has been a director of the general partner of CVR Partners. Prior to joining Coffeyville Resources in February 2004, Mr. Riemann held various positions associated with the Crop Production and Petroleum Energy Division of Farmland Industries, Inc. (“Farmland”) for over 30 years, including, most recently, Executive Vice President of Farmland and President of Farmland’s Energy and Crop Nutrient Division. In this capacity, he was directly responsible for managing the petroleum refining operation and all domestic fertilizer operations, which included the Trinidad and Tobago nitrogen fertilizer operations. His leadership also extended to managing Farmland’s interests in SF Phosphates in Rock Springs, Wyoming and Farmland Hydro, L.P., a phosphate production operation in Florida and managing all company-wide transportation assets and services. Mr. Riemann has served as a board member and board chairman on several industry organizations including the Phosphate Potash Institute, the Florida Phosphate Council and the International Fertilizer Association. He currently serves on the Board of The Fertilizer Institute. Mr. Riemann received a Bachelor of Science degree from the University of Nebraska and an MBA from Rockhurst University. Mr. Riemann’s extensive knowledge of all aspects of our petroleum refining operations gained through his significant management experience provides insight into the issues facing our business, and qualifies him to serve on the board of directors of our general partner.

Susan M. Ball has served as Chief Financial Officer and Treasurer of our general partner since our inception in September 2012. Ms. Ball has also served as the Chief Financial Officer and Treasurer of CVR Energy and of the general partner of CVR Partners since August 2012, and prior to that, as Vice President, Chief Accounting Officer and Assistant Treasurer of CVR Energy and the general partner of CVR Partners since October 2007 and as Vice President, Chief Accounting Officer and Assistant Treasurer for Coffeyville Resources since May 2006. Ms. Ball has more than 25 years of experience in the accounting industry, with more than 12 years serving clients in the public accounting industry. Prior to joining CVR Energy, she served as a Tax Managing Director with KPMG LLP, where she was responsible for all aspects of federal and state income tax compliance and tax consulting, which included a significant amount of mergers and acquisition work on behalf of her clients. Ms. Ball received a Bachelor of Science in Business Administration from Missouri Western State University and is a Certified Public Accountant.

 

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Edmund S. Gross has served as Senior Vice President, General Counsel and Secretary of our general partner since our inception in September 2012. Mr. Gross has also served as the Senior Vice President, General Counsel and Secretary of CVR Energy since October 2007, Vice President, General Counsel and Secretary of CVR Energy since September 2006 and General Counsel and Secretary of Coffeyville Resources since July 2004. Since October 2007, Mr. Gross has also served as the Senior Vice President, General Counsel and Secretary of the general partner of CVR Partners. Prior to joining Coffeyville Resources, Mr. Gross was Of Counsel at Stinson Morrison Hecker LLP in Kansas City, Missouri from 2002 to 2004, was Senior Corporate Counsel with Farmland from 1987 to 2002 and was an associate and later a partner at Weeks, Thomas & Lysaught, a law firm in Kansas City, Kansas, from 1980 to 1987. Mr. Gross received a Bachelor of Arts degree in history from Tulane University, a Juris Doctor from the University of Kansas and an MBA from the University of Kansas.

Robert W. Haugen has served as Executive Vice President, Refining Operations of our general partner since our inception in September 2012. Mr. Haugen joined CVR Energy on June 24, 2005 and has served as Executive Vice President, Refining Operations at CVR Energy since September 2006. He served as Executive Vice President— Engineering & Construction at Coffeyville Resources since June 24, 2005. Mr. Haugen brings more than 30 years of experience in the refining, petrochemical and nitrogen fertilizer business to CVR Energy. Prior to joining us, Mr. Haugen was a managing director and Partner of Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. On leave from Prudentia, he served as the Senior Oil Consultant to the Iraqi Reconstruction Management Office for the U.S. Department of State. Prior to joining Prudentia Energy, Mr. Haugen served in numerous engineering, operations, marketing and management positions at the Howell Corporation and at the Coastal Corporation. Upon the merger of Coastal and El Paso in 2001, Mr. Haugen was named Vice President and General Manager for the Coastal Corpus Christi Refinery and later held the positions of Vice President of Chemicals and Vice President of Engineering and Construction. Mr. Haugen received a Bachelor of Science degree in Chemical Engineering from the University of Texas.

Wyatt E. Jernigan has served as Executive Vice President, Crude Oil Acquisition and Petroleum Marketing of our general partner since our inception in September 2012. Mr. Jernigan has served as Executive Vice President, Crude Oil Acquisition and Petroleum Marketing of CVR Energy since September 2006 and as Executive Vice President—Crude & Feedstocks of Coffeyville Resources since June 24, 2005. Mr. Jernigan has more than 30 years of experience in the areas of crude oil and petroleum products related to trading, marketing, logistics and business development. Most recently, Mr. Jernigan was a managing director with Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. Most of his career was spent with Coastal Corporation and El Paso, where he held several positions in crude oil supply, petroleum marketing and asset development, both domestic and international. Following the merger between Coastal Corporation and El Paso in 2001, Mr. Jernigan assumed the role of Managing Director for Petroleum Markets Originations. Mr. Jernigan attended Virginia Wesleyan College, majoring in Sociology and has training in petroleum fundamentals from the University of Texas.

Christopher G. Swanberg has served as Vice President, Environmental, Health and Safety of our general partner since our inception in September 2012. Mr. Swanberg has also served as Vice President, Environmental, Health and Safety of CVR Energy since September 2006, as Vice President, Environmental, Health and Safety at Coffeyville Resources since June 2005 and as Vice President, Environmental, Health and Safety of the general partner of CVR Partners since October 2007. He has served in numerous management positions in the petroleum refining industry such as Manager, Environmental Affairs for the refining and marketing division of Atlantic Richfield Company (ARCO) and Manager, Regulatory and Legislative Affairs for Lyondell-Citgo Refining. Mr. Swanberg’s experience includes technical and management assignments in project, facility and corporate staff positions in all environmental, safety and health areas. Prior to joining Coffeyville Resources, he was Vice President of Sage Environmental Consulting, an environmental consulting firm focused on petroleum refining and petrochemicals, from September 2002 to June 2005. Mr. Swanberg received a Bachelor of Science degree in Environmental Engineering Technology from Western Kentucky University and an MBA from the University of Tulsa.

 

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David L. Landreth has served as Vice President, Economics and Planning of our general partner since our inception in September 2012. Mr. Landreth has also served as Vice President, Economics and Planning of Coffeyville Resources Refining and Marketing since January 2009. Mr. Landreth 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. He has served in numerous management positions in the petroleum industry. Most of his career was in various refining and marketing positions with the Coastal Corporation. Following the merger between Coastal and El Paso in 2001, Mr. Landreth assumed the position of Director of Refining Optimization and Commercial Management. Before joining Coffeyville Resources in 2005, he was the Director of Refining and Marketing Economics and Planning at Holly Corporation in Dallas. Mr. Landreth received a B.S. degree in Chemistry from Northwestern Oklahoma State University.

Carl C. Icahn has served as chairman of the board and a director of Starfire Holding Corporation, a privately-held holding company, and chairman of the board and a director of various subsidiaries of Starfire, since 1984. Since August 2007, through his position as Chief Executive Officer of Icahn Capital LP, a wholly owned subsidiary of Icahn Enterprises L.P., and certain related entities, Mr. Icahn’s principal occupation is managing private investment funds, including Icahn Partners LP, Icahn Partners Master Fund LP, Icahn Partners Master Fund II LP and Icahn Partners Master Fund III LP. From November 2004 to August 2007, Mr. Icahn conducted this occupation through his entities CCI Onshore Corp. and CCI Offshore Corp. Since November 1990, Mr. Icahn has been chairman of the board of Icahn Enterprises G.P. Inc., the general partner of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion). Mr. Icahn has been: chairman of the board of CVR Energy since June 2012; chairman of the board of Tropicana Entertainment Inc., a company that is primarily engaged in the business of owning and operating casinos and resorts, since March 2010; a director of Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since December 2007, and the non-executive chairman of the board of Federal-Mogul since January 2008; President and a member of the executive committee of XO Holdings, a competitive provider of telecom services, since September 2011, and chairman of the board and a director of its predecessors since January 2003; and chairman of the board and a director of American Railcar Industries, Inc., a railcar manufacturing company, since 1994. Mr. Icahn was previously: a director of WestPoint Home LLC, a home textiles manufacturer, from October 2005 until December 2011; a director of Cadus Corporation, a company engaged in the ownership and licensing of yeast-based drug discovery technologies, from July 1993 to July 2010; a director of Blockbuster Inc., a provider of in-home movie rental and game entertainment, from May 2005 to January 2010; a director of Motricity Inc., a mobile data services provider, from April 2008 to January 2010; a director of Yahoo! Inc., a company that provides Internet services to users, advertisers, publishers and developers worldwide, from August 2008 to October 2009; a director of WCI Communities, Inc., a homebuilding company, from August 2007 to September 2009, and was chairman of the board of WCI from September 2007 to September 2009; a director of ImClone Systems Incorporated, a biopharmaceutical company, from September 2006 to November 2008, and was chairman of the board of ImClone from October 2006 to November 2008; chairman of the board of GB Holdings, Inc., which owned an interest in Atlantic Coast Holdings, Inc., the former owner and operator of The Sands Hotel and Casino in Atlantic City, from September 2000 to February 2007; chairman of the board and president of Icahn & Co., Inc., a registered broker-dealer and a member of the National Association of Securities Dealers, from 1968 to 2005; and the president and a director of Stratosphere Corporation, the owner and operator of the Stratosphere Hotel and Casino in Las Vegas, Nevada, which, until February 2008, was a subsidiary of Icahn Enterprises, from October 1998 to May 2004. Mr. Icahn received his B.A. from Princeton University. Mr. Icahn brings to his role as director his significant business experience and leadership role as director in various companies as discussed above. In addition, Mr. Icahn is uniquely qualified based on his historical background for creating value in companies across multiple industries. Mr. Icahn has proven to be a successful investor over the past 40 years.

Vincent J. Intrieri. Mr. Intrieri has been employed by Icahn related entities since October 1998 in various investment related capacities. Since January 2008, Mr. Intrieri has served as Senior Managing Director of Icahn Capital LP, the entity through which Carl C. Icahn manages private investment funds. In addition, since

 

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November 2004, Mr. Intrieri has been a Senior Managing Director of Icahn Onshore LP, the general partner of Icahn Partners LP, and Icahn Offshore LP, the general partner of Icahn Partners Master Fund LP, Icahn Partners Master Fund II LP and Icahn Partners Master Fund III LP, entities through which Mr. Icahn invests in securities.

Mr. Intrieri has been a director of: Navistar International Corporation, a truck and engine manufacturer, since October 2012; Chesapeake Energy Corporation, an oil and gas exploration and production company, since June 2012; CVR Energy, Inc., an independent petroleum refiner and marketer of high value transportation fuels, since May 2012; and Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since December 2007. Mr. Intrieri was previously: a director of Icahn Enterprises G.P. Inc., the general partner of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion) from July 2006 through September 2012, and was Senior Vice President of Icahn Enterprises G.P. Inc. from October 2011 through September 2012; a director of Dynegy Inc., a company primarily engaged in the production and sale of electric energy, capacity and ancillary services, from March 2011 through September 2012; chairman of the board and a director of PSC Metals Inc., a metal recycling company, from December 2007 through April 2012; a director of Motorola Solutions, Inc., a provider of communication products and services, from January 2011 through 2012; a director of XO Holdings, a competitive provider of telecom services, from February 2006 through August 2011; a director of National Energy Group, Inc., a company that was engaged in the business of managing the exploration, production and operations of natural gas and oil properties, from December 2006 through June 2011; a director of American Railcar Industries, Inc., a railcar manufacturing company, from August 2005 until March 2011, and was a Senior Vice President, the Treasurer and the Secretary of American Railcar Industries from March 2005 to December 2005; a director of WestPoint Home LLC, a home textiles manufacturer, from November 2005 through March 2011; chairman of the board and a director of Viskase Companies, Inc., a meat casing company, from April 2003 through March 2011; a director of WCI Communities, Inc., a homebuilding company, from August 2008 through September 2009; a director of Lear Corporation, a global supplier of automotive seating and electrical power management systems and components, from November 2006 through November 2008; and President and Chief Executive Officer of Philip Services Corporation, an industrial services company, from April 2005 through September 2008.

CVR Energy, Federal-Mogul, PSC Metals, XO Holdings, National Energy Group, American Railcar Industries, WestPoint Home, Viskase Companies and Philip Services each are or previously were indirectly controlled by Carl C. Icahn. Mr. Icahn also has or previously had a non-controlling interest in Navistar, Chesapeake Energy, Dynegy, Motorola Solutions, WCI Communities and Lear through the ownership of securities.

Mr. Intrieri graduated in 1984, with Distinction, from The Pennsylvania State University (Erie Campus) with a B.S. in Accounting. Mr. Intrieri was a certified public accountant. Based upon Mr. Intrieri’s significant experience as a director of various companies which enables him to understand the complex business and financial issues that a company may face, we believe that Mr. Intrieri has the requisite set of skills to serve as a Board member.

Daniel A. Ninivaggi has served as President of Icahn Enterprises L.P. and its general partner, Icahn Enterprises G.P. Inc., since April 2010, as its Chief Executive Officer since August 2010, and as a director since March 2012. Icahn Enterprises is a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion. From 2003 until July 2009, Mr. Ninivaggi served in a variety of executive positions at Lear Corporation, a global supplier of automotive seating and electrical power management systems and components, including as General Counsel from 2003 to 2007, as Senior Vice President from 2004 until 2006, and most recently as Executive Vice President and Chief Administrative Officer from 2006 to 2009. Lear Corporation filed for bankruptcy in July 2009 and emerged in November 2009. Prior to joining Lear Corporation, from 1998 to 2003, Mr. Ninivaggi was a partner with the law firm of Winston & Strawn LLP, specializing in corporate finance, mergers and acquisitions, and corporate governance. Mr. Ninivaggi also served as Of Counsel to Winston & Strawn LLP from July 2009 to March 2010. Mr. Ninivaggi has been a director of: CVR Energy since May 2012; CVR GP, LLC,

 

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the general partner of CVR Partners, since May 2012; Viskase Companies, Inc., a meat casing company, since June 2011; XO Holdings, a competitive provider of telecom services, since August 2010; and Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since March 2010. From January 2011 to May 2012, Mr. Ninivaggi served as the Interim President and Interim Chief Executive Officer, and since January 2011, he has served as a director, of Tropicana Entertainment Inc., a company that is primarily engaged in the business of owning and operating casinos and resorts. Mr. Ninivaggi was previously a director of: Motorola Mobility Holdings, Inc., a provider of mobile communication devices, video and data delivery solutions, from December 2010 to May 2012; and CIT Group Inc., a bank holding company, from December 2009 to May 2011. CVR Energy, CVR Partners, Viskase Companies, XO Holdings, Federal-Mogul and Tropicana Entertainment are each indirectly controlled by Carl C. Icahn. Mr. Icahn previously had interests in Motorola Mobility and CIT Group through the ownership of securities. Mr. Ninivaggi received a B.A. in History from Columbia University in 1986, a Masters of Business Administration from the University of Chicago in 1988 and a J.D. from Stanford Law School in 1991. Based upon Mr. Ninivaggi’s strong background in operations and management having served in various executive roles and having served on a number of public and private boards, including Motorola Mobility and CIT Group, we believe that Mr. Ninivaggi has the requisite set of skills to serve as a Board member.

SungHwan Cho has served as Chief Financial Officer of Icahn Enterprises G.P. Inc., the general partner of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion), since March 2012. Prior to that time, he was Senior Vice President and previously Portfolio Company Associate at Icahn Enterprises since October 2006. From 2004 to 2006, Mr. Cho served as Director of Finance for Atari, Inc., a publisher of interactive entertainment products. From 1999 to 2002, Mr. Cho served as Director of Corporate Development and Director of Product Development at Talk America, a telecommunications provider to small business and residential customers. From 1996 to 1999, he was an investment banker at Salomon Smith Barney in New York and Tokyo. Mr. Cho has been a director of: Icahn Enterprises G.P. Inc. since September 2012; CVR Energy since May 2012; CVR GP, LLC, the general partner of CVR Partners, since May 2012; Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since May 2012; XO Holdings, a competitive provider of telecom services, since August 2011; American Railcar Industries, Inc., a railcar manufacturing company, since June 2011; Take-Two Interactive Software Inc., a publisher of interactive entertainment products, since April 2010; WestPoint Home LLC, a home textiles manufacturer, since January 2008; PSC Metals Inc., a metal recycling company, since December 2006; and Viskase Companies, Inc., a meat casing company, since November 2006. CVR Energy, CVR Partners, Federal-Mogul, XO Holdings, American Railcar Industries, WestPoint Home, PSC Metals and Viskase Companies each are indirectly controlled by Carl C. Icahn. Mr. Icahn also has a non-controlling interest in Take-Two Interactive Software through the ownership of securities. Mr. Cho received a B.S. in Computer Science from Stanford University and an MBA from New York University, Stern School of Business. Based upon Mr. Cho’s deep understanding of finance and risk obtained from his past experience, including his position as an investment banker at Salomon Smith Barney, we believe that Mr. Cho has the requisite set of skills to serve as a Board member.

Samuel Merksamer is a Managing Director of Icahn Capital LP, a subsidiary of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion), where he has been employed since May 2008. Mr. Merksamer is responsible for identifying, analyzing and monitoring investment opportunities and portfolio companies for Icahn Capital. From 2003 until 2008, Mr. Merksamer was an analyst at Airlie Opportunity Capital Management, a hedge fund management company, where he focused on high yield and distressed investments. Mr. Merksamer has been a director of: CVR Energy, Inc., an independent petroleum refiner and marketer of high value transportation fuels, since May 2012; American Railcar Industries, Inc., a railcar manufacturing company, since June 2011; Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since September 2010; Viskase Companies, Inc., a meat casing company, since January 2010; and PSC Metals Inc., a metal recycling company, since March 2009. Mr. Merksamer was previously a director of Dynegy Inc., a company primarily engaged in the production and sale of electric energy,

 

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capacity and ancillary services, from March 2011 through September 2012. CVR Energy, American Railcar Industries, Federal-Mogul, Viskase Companies and PSC Metals are each indirectly controlled by Carl C. Icahn. Mr. Icahn also has a non-controlling interest in Dynegy Inc. through the ownership of securities. Mr. Merksamer received an A.B. in Economics from Cornell University in 2002. Based upon Mr. Merksamer’s strong record as a financial analyst and his service on a number of public and private boards, which have provided him with a broad understanding of the operational, financial and strategic issues facing public and private companies, we believe that Mr. Merksamer has the requisite set of skills to serve as a Board member.

Glenn R. Zander has served as a director of CVR Energy since May 2012. Mr. Zander was the Chief Executive Officer, President and director of Aloha Airgroup, Inc., a privately owned passenger and cargo transportation airline, from 1994 to 2004. From 1990 to 1994, Mr. Zander served as Vice Chairman, Co-Chief Executive Officer and director of Trans World Airlines, an international airline. He also served as Chief Financial Officer of TWA within that period. During 1992 and 1993, Mr. Zander served as the Chief Restructuring Officer of TWA following its Chapter 11 bankruptcy in 1992 and its emergence therefrom in 1993. From 2004 to 2009, Mr. Zander served as a director of Centerplate, Inc., a provider of food/concession services at sports facilities and convention centers in the United States and Canada. TWA was formerly indirectly controlled by Carl C. Icahn. Based upon Mr. Zander’s substantial operational background, having served as chief executive officer and chief financial officer and other executive positions, we believe that Mr. Zander has the requisite set of skills to serve as a Board member.

Jon R. Whitney has been a member of the board of directors of CVR Partners’ general partner since June 2011. He previously worked at Colorado Interstate Gas Company (CIG), a natural gas transmission company, from 1968 until 2001. He served as President and Chief Executive Officer of CIG from 1990 until it merged with El Paso Corporation in 2001. After leaving CIG, he served as Co-Chairman of the Board for TransLink, an independent electric power system operator, was a member of Peak Energy Ventures, LLC, a natural gas consulting company, and served on the boards of directors of Storm Cat Energy Corporation, Patina Oil and Gas Corporation (prior to its merger with Noble Energy in 2005), American Oil and Gas Corporation (prior to its merger with Hess Corporation in 2010), Bear Cub Energy and Bear Paw Energy. He also held committee positions with the Interstate Natural Gas Association of America and the American Gas Association. He is currently a director of Bear Tracker Energy LLC, a private company in the midstream energy business. We believe Mr. Whitney’s experience in the natural gas industry and as a director to multiple companies in the energy space is an asset to our board.

Keith Cozza is currently the Chief Financial Officer of Icahn Associates Holding LLC, a position he has held since 2006. Mr. Cozza served as Controller at Icahn Associates Holding LLC from 2004 to 2006. Prior to that Mr. Cozza was a senior assurance associate at Grant Thornton LLP. Mr. Cozza has been a director of Icahn Enterprises G.P. Inc., the general partner of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion), since September 2012; and XO Holdings, a competitive provider of telecom services, since August 2011. Mr. Cozza was previously a director of MGM Holdings Inc., an entertainment company focused on the production and distribution of film and television content, from April 2012 to August 2012. XO Holdings is indirectly controlled by Carl C. Icahn. Mr. Icahn also previously had a non-controlling interest in MGM Holdings through the ownership of securities. Mr. Cozza holds a B.S. in Accounting from the University of Dayton. Based upon his extensive operations background in finance and accounting and substantial knowledge of the capital markets having overseen numerous complex capital raising transactions, we believe that Mr. Cozza has the requisite skills to serve as a Board member.

Kenneth Shea is the President of Coastal Capital Management LLC, an affiliate of Coastal Development, LLC, a New York based privately-held developer of resort destinations, luxury hotels and casino gaming facilities. Prior to joining Coastal in September 2009, from July 2008 to August 2009, Mr. Shea was a Managing Director for Icahn Capital LP, a wholly owned subsidiary of Icahn Enterprises L.P. (a diversified holding company controlled by Carl Icahn that is engaged in a variety of businesses, including investment, automotive,

 

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energy, gaming, railcar, food packaging, metals, real estate and home fashion) through which Mr. Icahn manages various private investment funds, including Icahn Partners, Icahn Master, Icahn Master II and Icahn Master III. At Icahn Capital, Mr. Shea had responsibility for all principal investments in the gaming and leisure industries. Prior to serving at Icahn Capital, Mr. Shea was employed by Bear, Stearns & Co., Inc., from 1996 to 2008, where he was a Senior Managing Director and global head of the Gaming and Leisure investment banking department. At Bear, Stearns, Mr. Shea oversaw the execution of various complex capital raising and merger & acquisition transactions for a wide variety of public and private companies. Mr. Shea holds a Bachelor of Arts in Economics, magna cum laude, from Boston College and an M.B.A. from the University of Virginia’s Darden School. Based upon his significant experience in corporate finance, mergers and acquisitions and investing, and deep knowledge of the capital markets, we believe that Mr. Shea has the requisite skills to serve as a Board member.

Compensation Discussion and Analysis

We were formed in September 2012. We are a new subsidiary formed to hold the petroleum refining and logistics assets which, prior to the closing of this offering, comprised a portion of the assets of CVR Energy. As such, our general partner did not participate in the design or implementation of, nor accrue any obligations with respect to compensation for its directors and executive officers that may provide services to us during the fiscal year ending December 31, 2012. Accordingly, we do not have historical compensation information to disclose at this time.

We will not directly employ any of the persons responsible for managing our business. All of the initial executive officers that will be responsible for managing our day to day affairs are also current officers of CVR Energy or its subsidiaries, and therefore will have responsibilities for both us, our general partner and CVR Energy and its subsidiaries after this offering. We will enter into a services agreement with our general partner and CVR Energy in connection with this offering, which will provide, among other matters, that:

 

   

CVR Energy will make available to our general partner the services of CVR Energy executive officers and employees who serve as our general partner’s executive officers; and

 

   

We, our general partner and our subsidiaries, as the case may be, will be obligated to reimburse CVR Energy for any allocated portion of the costs that CVR Energy incurs in providing compensation and benefits to such CVR Energy employees, with the exception of costs attributable to share-based compensation.

Under the services agreement, either our general partner, our subsidiaries or we will pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other than administrative personnel, who provide us services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide us services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement. Following the first anniversary of this offering, either CVR Energy or our general partner may terminate the services agreement upon at least 180 days’ notice. For more information on this services agreement, see “Certain Relationships and Related Party Transactions—Agreements with CVR Energy.”

The compensation of the executive officers of our general partner is set by CVR Energy. The executive officers of our general partner currently receive all of their compensation and benefits for employment related to our business from CVR Energy. Although we bear an allocated portion of CVR Energy’s costs of providing compensation and benefits to the CVR Energy employees who serve as the executive officers of our general partner, we will have no control over such costs and do not establish or direct the compensation policies or practices of CVR Energy. We are required to pay all compensation amounts allocated to us by CVR Energy

 

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(except for share-based compensation granted by CVR Energy), although we may object to amounts that we deem unreasonable. The executive officers of our general partner, as well as the employees of CVR Energy who may provide services to us, may participate in employee benefit plans and arrangements sponsored by CVR Energy, including plans that may be established in the future. Aside from the long-term incentive plan described below, neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.

In the future, the executive officers and directors of our general partner may receive equity-based compensation in connection with the long-term incentive plan that we intend to adopt (described below), and we will be responsible for all costs associated with the grant of awards under such long-term incentive plan. All determinations with respect to awards to be made under our long-term incentive plan to executive officers and other employees of our general partner and of CVR Energy will be made by the board of directors of our general partner, although our general partner’s board of directors may consult with CVR Energy when making such decisions. Responsibility and authority for compensation-related decisions for executive officers and other personnel employed directly by our general partner, if any, will reside with our general partner.

The individuals that we consider to be “named executive officers” for purposes of this filing are as follows:

 

   

John J. Lipinski—Chief Executive Officer

 

   

Susan M. Ball—Chief Financial Officer

 

   

Stanley A. Riemann—Chief Operating Officer

 

   

Edmund S. Gross—Senior Vice President, General Counsel and Secretary

 

   

Robert W. Haugen—Executive Vice President, Refining Operations

CVR Refining, LP Long-Term Incentive Plan

We, through our general partner, intend to adopt the CVR Refining, LP Long-Term Incentive Plan (the “LTIP”) prior to the effectiveness of this offering for the employees, consultants and the directors of our general partner and its affiliates who perform services for us. We, through our general partner, intend to adopt the LTIP prior to the effectiveness of the registration statement of which this prospectus forms a part for the employees, consultants and the directors of our general partner and its affiliates who perform services for us. The description of the LTIP set forth below is a summary of the material features of the plan. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, a copy of which has been filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units.

General

The LTIP will allow (as determined by the board of directors of our general partner or an alternative committee appointed by the board of our general partner (as described below)) for the provision of grants of (1) unit options, (2) unit appreciation rights, (3) restricted units, (4) phantom units, (5) unit awards, (6) substitute awards, (7) other unit-based awards, (8) cash awards, (9) performance awards, and (10) distribution equivalent rights (collectively referred to as “awards”).

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will

 

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be granted, determine the amount of awards (measured in cash or in common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP, and execute all other responsibilities permitted or required under the LTIP.

Common Units Available for Issuance

The LTIP authorizes a pool of 11,070,000 common units representing limited partner interests in CVR Refining. Whenever any outstanding award granted under the LTIP expires, is canceled, is forfeited, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of common units available for issuance under the LTIP shall be increased by the number of common units previously allocable to the expired, canceled, settled or otherwise terminated portion of the award.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly-issued common units, common units acquired by our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. With respect to options, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise. Thus, we will bear the cost of the options. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Types of Awards

Options

The committee is authorized to grant options to participants. The exercise price of any option must be equal to or greater than the fair market value of a common unit on the date the option is granted. The term of an option cannot exceed ten years, except that options may be exercised for up to one year following the death of a participant even if such period extends beyond the ten year term. Subject to the terms of the LTIP, the option’s terms and conditions, which include but are not limited to, exercise price, vesting, treatment of the award upon termination of employment, and expiration of the option, would be determined by the committee and set forth in an award agreement. Payment for common units purchased upon exercise of an option must be made in full at the time of purchase. The exercise price may be paid (i) in cash or its equivalent (e.g., check), (ii) in common units already owned by the participant, on terms determined by the committee, (iii) in the form of other property as determined by the committee, (iv) through participation in a “cashless exercise” procedure involving a broker or (v) by a combination of the foregoing.

Unit Appreciation Rights (“UARs”)

The committee is authorized, either alone or in connection with the grant of an option, to grant UARs to participants. The terms and conditions of a UAR award would be determined by the committee and set forth in an award agreement. UARs may be exercised at such times and be subject to such other terms, conditions, and provisions as the committee may impose. The committee may establish a maximum amount per common unit that would be payable upon exercise of a UAR. A UAR would entitle the participant to receive, on exercise of the UAR, an amount equal to the product of (i) the excess of the fair market value of a unit on the date preceding the date of surrender over the fair market value of a common unit on the date the UAR was issued, or, if the UAR is related to an option, the per-unit exercise price of the option and (ii) the number of common units subject to the UAR or portion thereof being exercised. Subject to the discretion of the committee, payment of a UAR may be made in cash, common units or a combination thereof.

 

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Restricted Units and Phantom Units

The committee is authorized to grant restricted units and phantom units, subject to such terms and conditions as determined by the committee and set forth in an award agreement. Restricted units and phantom units may not be sold, transferred, pledged, or otherwise transferred until the time, or until the satisfaction of such other terms, conditions, and provisions, as the committee may determine. When the period of restriction on restricted units terminates, unrestricted common units would be delivered. Unless the committee determines otherwise at the time of grant, restricted units carry full voting rights and other rights as a unitholder, including rights to receive distributions. At the time an award of restricted units is granted, the committee may determine that the payment to the participant of distributions would be deferred until the lapsing of the restrictions imposed upon the common units and whether deferred distributions are to be converted into additional common units or held in cash. The deferred distributions would be subject to the same forfeiture restrictions and restrictions on transferability as the restricted units with respect to which they were paid. Each phantom unit would represent the right of the participant to receive a payment upon vesting of the phantom unit or on any later date specified by the committee. The payment would equal the fair market value of a common unit as of the date the phantom unit was granted, the vesting date, or such other date as determined by the committee at the time the phantom unit was granted. At the time of grant, the committee may provide a limitation on the amount payable in respect of each phantom unit. The committee may provide for a payment in respect of phantom units in cash or in common units having a fair market value equal to the payment to which the participant has become entitled.

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Substitute Awards

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees or directors as a result of a merger, consolidation or acquisition by us, an affiliate of another entity or the assets of another entity. Such substitute awards that are options or UARs may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Internal Revenue Code and its regulations, and other applicable laws and exchange rules.

Other Unit-Based Awards

The committee is authorized to grant other unit-based awards to participants as additional compensation for service to us or a subsidiary or in lieu of cash or other compensation to which participants have become entitled. Other unit-based awards may be subject to other terms and conditions, which may vary from time to time and among participants, as the committee determines to be appropriate.

Cash Awards

The LTIP will permit the grant of awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

 

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Distribution Equivalent Rights

The committee is authorized to grant distribution equivalent rights either in tandem with an award or as a separate award. The terms and conditions applicable to each distribution equivalent right would be determined by the committee and set forth in an award agreement. Amounts payable in respect of distribution equivalent rights may be payable currently or, if applicable, deferred until the lapsing of restrictions on the distribution equivalent rights or until the vesting, exercise, payment, settlement or other lapse of restrictions on the award to which the distribution equivalent rights relate; provided that distribution equivalent rights may not contain payment or other terms that could adversely affect the option or award to which it relates under Section 409A of the Internal Revenue Code or otherwise.

Amendment and Termination of the LTIP

The board of directors of our general partner has the right to amend the LTIP, except that it may not amend the LTIP in a manner that would impair or adversely affect the rights of the holder of an award without the award holder’s consent. In addition, the board of directors of our general partner may not amend the LTIP absent unitholder approval to the extent such approval is required by applicable law, regulation or exchange requirement. The LTIP will terminate on the tenth anniversary of the date of approval by the board of directors of our general partner. The board of directors of our general partner may terminate the LTIP at any earlier time, except that termination cannot in any manner impair or adversely affect the rights of the holder of an award without the award holder’s consent.

No Repricing of Options or UARs

Unless our unitholders approve such adjustment, the committee would not have authority to make any adjustments to options or UARs that would reduce or would have the effect of reducing the exercise price of an option or UAR previously granted under the LTIP (except as provided under “Adjustments” below).

Change in Control

The effect, if any, of a change in control on each of the awards granted under the LTIP may be set forth in the applicable award agreement.

Adjustments

In the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, unit distribution, issuance of warrants, rights or debentures, stock distribution, stock split or reverse stock split, cash distribution, property distribution, combination or exchange of units, repurchase of units, or similar transaction or other change in corporate structure affecting our common units, adjustments and other substitutions will be made to the LTIP, including adjustments in the maximum number of common units subject to the LTIP and adjustments to outstanding awards granted under the LTIP as the committee determines appropriate. In the event of our merger or consolidation, liquidation or dissolution, outstanding options and awards will be treated as provided for in the agreement entered into in connection with the transaction, or, if not so provided in such agreement, holders of options awards will be entitled to receive in respect of each common unit subject to any outstanding options or awards, upon exercise of any option or payment or transfer in respect of any award, the same number and kind of stock, securities, cash, property or other consideration that each holder of a common unit was entitled to receive in the transaction in respect of a common unit; provided, however, that such stock, securities, cash, property, or other consideration shall remain subject to all of the conditions, restrictions and performance criteria which were applicable to the options and awards prior to such transaction.

 

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CVR Energy’s Compensation Programs

As noted above, we are a newly formed subsidiary of CVR Energy and neither we nor our general partner have been or will be responsible for the design or implementation of compensation of our named executive officers prior to the closing of this offering. Accordingly, we have no historical compensation information to present. As previously discussed, the majority of compensation-related decisions made with respect to our named executive officers (other than any grants under our LTIP) will be the responsibility of CVR Energy and its compensation committee. Thus we have provided a summarized discussion of the policies and programs of CVR Energy and the compensation committee of the board of directors of CVR Energy, as well as all compensation paid by CVR Energy to our shared named executive officers in 2012, below, to provide insight into the current compensation program at CVR Energy. We expect that Messrs. Lipinski, Riemann, Gross and Haugen, and Ms. Ball will be considered named executive officers of CVR Energy for the 2012 year, and detailed information about the compensation that was provided to these individuals by CVR Energy for the 2012 year will be included in the next CVR Energy proxy statement. Detailed information of the compensation provided to such individuals during the 2011 year (other than with respect to Ms. Ball, who was not a named executive officer at CVR Energy for the 2011 year), which is very similar to the compensation provided in the 2012 year, can be found under the headings “Compensation Discussion and Analysis” and “Compensation of Executive Officers” in the most recent CVR Energy proxy statement that was filed with the SEC on July 2, 2012.

CVR Energy Historical Compensation and Compensation Program Highlights

Compensation Objectives

CVR Energy’s executive compensation objectives are threefold:

 

   

To align the executive officer’s interest with that of CVR Energy’s stockholders and stakeholders, which provides long-term economic benefits to the stockholders;

 

   

To provide competitive financial incentives in the form of salary, bonuses and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and

 

   

To maintain a compensation program whereby the executive officers, through exceptional performance and equity ownership, will have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders.

CVR Energy takes these main objectives into consideration when creating its compensation programs, when setting each element of compensation under those programs, and when determining the proper mix of the various compensation elements for each of its executive officers.

Elements of the Compensation Program

For 2012, the three primary components of CVR Energy’s compensation program were base salary, an annual performance-based cash bonus and equity awards. While these three components are related, they are viewed as separate and analyzed as such. The named executive officers are also provided with health and welfare benefits that are generally available to CVR Energy’s other salaried employees.

CVR Energy believes that equity compensation is the primary motivator in attracting and retaining executive officers. Salary and cash bonuses are viewed as secondary. However, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.

CVR Energy’s compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is equity compensation. The decision is strictly made on a subjective and individual basis after consideration of all relevant factors. The Chief Executive Officer of CVR Energy, while not a member of CVR Energy’s compensation committee, reviews information provided by the committee’s compensation consultant, Longnecker & Associates (“Longnecker”), as well as other relevant market information and actively provides guidance and recommendations to the committee regarding the amount and form of the compensation of other executive officers and key employees.

 

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Longnecker has been engaged by CVR Energy on behalf of its compensation committee to assist the committee with its review of executive officers’ compensation levels and the mix of compensation as compared to peer companies, companies of similar size and other relevant market information. To this end, Longnecker performed a study including an analysis that management reviewed and then provided to the compensation committee for its use in making decisions regarding the salary, bonus and other compensation amounts paid to named executive officers. The following companies were included in the report and analysis prepared by Longnecker as members of CVR Energy’s “peer group”- the independent refining companies of HollyFrontier Corporation and Tesoro Corporation, Murphy Oil Corporation and the fertilizer businesses of CF Industries Holdings Inc. and The Mosaic Company. Although no specific target for total compensation or any particular element of compensation was set relative to CVR Energy’s peer group, the focus of Longnecker’s recommendations was centered on compensation levels at the median or 50th percentile of the peer group.

Base Salary. Each of the CVR Energy named executive officers has an employment agreement with CVR Energy that sets forth their initial base salaries. Base salaries are set at a level intended to enable CVR Energy to hire and retain executive officers, to enhance the executive officer’s motivation in a highly competitive and dynamic environment, and to reward individual and company performance. In determining base salary levels, the compensation committee of CVR Energy takes into account the following factors: (i) CVR Energy’s financial and operational performance for the year, (ii) the previous years’ compensation level for each executive officer, (iii) peer or market survey information for comparable public companies and (iv) recommendations of the chief executive officer, based on individual responsibilities and performance, including each executive officer’s commitment and ability to: (A) strategically meet business challenges, (B) achieve financial results, (C) promote legal and ethical compliance, (D) lead their own business or business team for which they are responsible and (E) diligently and effectively respond to immediate needs of the volatile industry and business environment.

Rather than establishing compensation solely on a formula-driven basis, decisions by CVR Energy’s compensation committee are made using an approach that considers several important factors in developing compensation levels. For example, CVR Energy’s compensation committee considers whether individual base salaries reflect responsibility levels and are reasonable, competitive and fair. In addition, in setting base salaries, CVR Energy’s compensation committee reviews published survey and peer group data prepared by Longnecker and considers the applicability of the salary data in view of the individual positions within CVR Energy.

Salaries are reviewed annually by CVR Energy’s compensation committee with periodic informal reviews throughout the year. Adjustments, if any, are usually made effective January 1 of the year immediately following the review. The compensation committee, with the assistance of Longnecker, most recently reviewed the level of base salary and cash bonus for each of the executive officers in 2012 in conjunction with their responsibilities and expectations for 2013. They concluded their review in December 2012, and set the following base salaries for the named executive officers: $950,000 for Mr. Lipinski (which is not a change from his 2012 salary), $490,000 for Mr. Riemann, $360,000 for Ms. Ball, $380,000 for Mr. Gross and $315,000 for Mr. Haugen. Individual performance, the practices of our peer group of companies as reflected in the analysis and report of Longnecker, and changes in the named executive officers’ positions and levels of responsibility were considered. Among these three factors, slightly more weight was given to the report and findings of Longnecker.

Annual Bonus. CVR Energy’s annual bonus program is designed to meet each of its compensation objectives. Specifically, CVR Energy’s annual bonus programs rewards executives only for measured company performance, thereby aligning the executive interest with those of its equity holders and encouraging the executives to focus on targeted performance. Further, the program also provides the executive with the opportunity to earn additional compensation, thereby making our total compensation package more competitive.

Information about total cash compensation paid by members of CVR Energy’s peer group is used in determining both the level of bonus award and the ratio of salary to bonus, as the compensation committee of CVR Energy believes that maintaining a level of bonus and a ratio of fixed salary to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in attracting and retaining executives. The compensation committee of CVR Energy also believes that a significant portion of executive officers’ compensation should be at risk, which means that a portion of the executive officers’ overall compensation is not

 

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guaranteed and is determined based on individual and company performance. Executive officers have greater potential bonus awards as the authority and responsibility of an executive increases. Employment agreements for each of the named executive officers provide that the executive is eligible to receive an annual cash bonus with a target bonus equal to a specified percentage of the relevant executive’s annual base salary. Under the employment agreements in effect during 2012 for CVR Energy’s named executive officers, target bonuses were the following percentages of each of individuals base salary: John J. Lipinski (250%), Susan M. Ball (100%), Stanley A. Riemann (200%), Edmund S. Gross (100%), and Robert W. Haugen, (120%). These target percentages were the result of individual negotiations between the named executive officers and CVR Energy, and were in correlation with the findings and recommendations by Longnecker based upon review of CVR Energy’s peer group, companies of similar size and other relevant market information. Specific bonus measures were determined by the board of directors of CVR Energy based on a review of CVR Energy’s peer group and discussions with CVR Energy management and the compensation committee of CVR Energy.

In March 2011, CVR Energy adopted the CVR Energy, Inc. Performance Incentive Plan (the “CVR Energy PIP”), pursuant to which all of the named executive officers had the opportunity to earn bonuses in respect of 2012. The payment of annual bonuses for the 2012 performance year to the named executive officers depended on the achievement of financial, operational and safety measures, which comprised 50%, 30% and 20% of the annual bonuses, respectively. At the beginning of the 2012 year, the compensation committee of CVR Energy approved the threshold, target and maximum performance goals with respect to each measure. Specific bonus measures were determined by CVR Energy based on a review of its peer group and discussions between CVR Energy’s board of directors and management and its compensation committee. The measures were selected based on optimizing operations, maintaining financial stability and providing a safe work environment intended to maximize CVR Energy’s overall performance resulting in increased stockholder value.

The following table shows the financial, operational and safety measures relevant to the CVR Energy named executive officers’ 2012 bonuses and the 2012 performance goals (threshold, target and maximum) for each measure (other than with respect to Mr. Haugen, who participates in a separate CVR Energy PIP specifically designed for the petroleum segment of CVR Energy’s business, described in greater details below). The financial measures included (1) consolidated adjusted EBITDA, which was derived from earnings before interest, taxes, depreciation and amortization, share-based compensation, loss on extinguishment of debt, first-in, first-out (FIFO) accounting impacts, non-controlling interest and asset impairment charges; (2) cash flows from operations less capital expenditures, where cash flows are adjusted for actual capital spent, inventory build and the initial fill of the Cushing tank farm and adjusted further for the capital spend associated with capital projects approved by the CVR Energy board and the board’s directed initiatives and fees; and (3) Wynnewood acquisition synergies, which is the economic sum of the following expected synergies: crude rate increase, overall crude differential improvement, reduced trucked crude freight costs, product and feedstock optimization between refineries, SG&A and miscellaneous improvements and optimizations and liquid yield improvements. Awards will not be paid with respect to the financial measures unless at least 50% of the relevant performance goal was achieved.

The operational measures were petroleum reliability for Coffeyville Resources LLC and Wynnewood (measured by crude throughput barrels per day). Awards will not be paid with respect to the operational measures unless the threshold of the relevant performance goal was achieved.

The 2012 safety measures will look to consolidated OSHA recordable injury statistics (based upon enterprise-wide OSHA injuries 13 between 2009-2011 and inclusive of petroleum, fertilizer and crude transportation), consolidated OSHA lost time injury statistics (based upon enterprise-wide OSHA lost time injuries 6 between 2009-2011 and inclusive of petroleum, fertilizer and crude transportation), consolidated EH&S severity statistics (based upon enterprise-wide EH&S severity 4 between 2009-2011 and inclusive of petroleum, fertilizer and crude transportation), consolidated air reportable releases (based upon enterprise-wide EPA reportable quantity releases and inclusive of petroleum and fertilizer operations), consolidated air reportable release quantity (based upon enterprise-wide EPA reportable quantity releases and inclusive of petroleum and

 

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fertilizer operations), consolidated tier 1 process safety events (based upon enterprise-wide API process safety events of petroleum and fertilizer operations), consolidated tier 2 process safety events (based upon enterprise-wide API process safety events of petroleum and fertilizer operations), reportable quantity spills for pipeline (based upon EPA reportable quantity releases inclusive of transportation operations), and spills to waters of U.S. pipelines (based upon EPA spills to U.S. waters inclusive of transportation operations), reportable quantity spills for trucking (based upon EPA reportable quantity releases inclusive of transportation operations), spills to waters of U.S. trucking (based upon EPA spills to U.S. waters inclusive of transportation operations), trucking incidents for on-road operations (based upon on-road, fault of CRCT and inclusive of transportation operations), and severity of trucking incidents (based upon EH&S applied factors inclusive of transportation operations). Awards will not be paid with respect to the safety measure unless the number of recordable events was less than the three year average. The executives receive 50%, 100%, or up to 150% of the applicable portion for levels of performance attained at threshold, target and maximum, respectively, and the percentage of the target amount for each respective measure that would be paid at various levels of achievement. At the time of this filing, the CVR Energy compensation committee has not certified the satisfaction of any performance goals, and final decisions regarding the 2012 bonuses have not been made. The table below is provided in order to show the breakdown of the performance goals, and the different levels set for each performance goal, for the potential bonuses that may be earned for the 2012 year.

 

2012 Performance Measure

 

2012 Performance Goals

Threshold/Target/Maximum

Consolidated adjusted EBITDA  

Threshold: $332 million

Target: $665 million

Maximum: $997 million

Consolidated adjusted cash flow  

Threshold: $120 million

Target: $240 million

Maximum: $360 million

Wynnewood Acquisition Synergies  

Threshold: $16 million

Target: $32 million

Maximum: $48 million

Coffeyville Petroleum Reliability Measures  

Threshold: 99,500 bpd

Target: 106,985 bpd

Maximum: 108,050 bpd

Wynnewood Petroleum Reliability Measures  

Threshold: 51,400 bpd

Target: 55,262 bpd

Maximum: 55,800 bpd

Consolidated OSHA recordable injury statistics  

Threshold: 18 recordable events

Target: 13 recordable events

Maximum: 9 recordable events

Consolidated OSHA lost time injury statistics  

Threshold: 8 recordable events

Target: 4 recordable events

Maximum: 0 recordable events

Consolidated EH&S severity statistics  

Threshold: 8 recordable events

Target: 4 recordable events

Maximum: 0 recordable events

Consolidated air reportable releases  

Threshold: 88 recordable events

Target: 78 recordable events

Maximum: 68 recordable events

 

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2012 Performance Measure

 

2012 Performance Goals

Threshold/Target/Maximum

Consolidated air reportable release quantity  

Threshold: 1,852,000 recordable events

Target: 1,436,000 recordable events

Maximum: 1,272,000 recordable events

Consolidated Tier 1 process safety events  

Threshold: 6 recordable events

Target: 3 recordable events

Maximum: 1 recordable events

Consolidated Tier 2 process safety events  

Threshold: 6 recordable events

Target: 3 recordable events

Maximum: 1 recordable events

Reportable quantity spills – Pipeline  

Threshold: 4 recordable events

Target: 3 recordable events

Maximum: 2 recordable events

Spills to Waters of U.S. – Pipeline  

Threshold: 2 recordable events

Target: 1 recordable events

Maximum: 0 recordable events

Reportable Quantity Spills – Trucking  

Threshold: 2 recordable events

Target: 1 recordable events

Maximum: 0 recordable events

Spills to Waters of U.S. – Trucking  

Threshold: 2 recordable events

Target: 1 recordable events

Maximum: 0 recordable events

Trucking Incidents – On-road  

Threshold: 3 recordable events

Target: 2 recordable events

Maximum: 1 recordable events

Trucking Incidents – Severity  

Threshold: 2 recordable events

Target: 1 recordable events

Maximum: 0 recordable events

The petroleum-focused CVR Energy PIP that Mr. Haugen participates in works in the same way as the plan described above, although the performance metrics are targeted solely on CVR Energy’s petroleum program for the financial measures. Operational measures and safety measures are the same for Mr. Haugen as described above, although the financial measures applicable to him are as follows:

 

2012 Performance Measure

 

2012 Performance Goals

Threshold/Target/Maximum

Consolidated adjusted EBITDA  

Threshold: $301 million

Target: $602 million

Maximum: $903 million

Capital Expenditures for Refining, Marketing and Crude Transportation  

Threshold: $195 million

Target: $170 million

Maximum: $161 million

Wynnewood Acquisition Synergies  

Threshold: $16 million

Target: $32 million

Maximum: $48 million

 

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An estimate of the amounts that will be earned by the named executive officers as a result of 2012 year performance pursuant to the CVR Energy PIP are set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table below, but CVR Energy will determine and pay all final amounts, which may differ from what is disclosed in the Summary Compensation Table.

Equity Awards

CVR Energy also uses equity incentives to reward long-term performance of its executive officers. The issuance of equity to executive officers is intended to satisfy CVR Energy’s compensation program objectives by generating significant future value for each executive officer if CVR Energy’s performance is outstanding and the value of CVR Energy’s equity increases for all of its stockholders. CVR Energy’s compensation committee believes that its equity incentives promote long-term retention of executives. Prior to 2012, the principal equity incentives for CVR Energy’s executive officers were negotiated to a large degree at the time of the acquisition of the CVR Energy business in June 2005 (with additional awards that were not originally allocated in June 2005 issued in December 2006) in order to bring CVR Energy’s compensation package in line with executives at private equity portfolio companies, based on the private equity market practices at that time.

CVR Energy established its long term incentive plan in connection with its initial public offering in October 2007 (the “CVR Energy LTIP”). CVR Energy’s compensation committee may elect to make restricted stock grants, option grants or other equity-based grants under the CVR Energy LTIP in its discretion or may recommend grants to CVR Energy’s board of directors for its approval, as determined by the committee in its discretion. Prior to 2012 CVR Energy granted restricted stock awards to its named executive officers. In accordance with the Transaction Agreement, CVR Energy exchanged these restricted stock awards for restricted stock units in the spring of 2012. In accordance with the Transaction Agreement, the unvested restricted stock awards were converted to restricted stock units that will settle in cash upon vesting. CVR Energy believes that the replacement restricted stock units provide the same retention incentive for the recipients of the awards, but will also prevent dilution to the CVR Energy shareholders by providing a cash payment rather than an equity payment. The replacement restricted stock unit awards were equivalent in number and value to the restricted stock awards that were cancelled and replaced.

In addition to the conversion of equity awards, in 2012 CVR Energy granted shares of restricted stock units to its named executive officers pursuant to the CVR Energy LTIP. The restricted stock units are subject to transfer restrictions and vesting requirements, provided the executive officers continue to serve as an employee of CVR Energy on applicable vesting dates, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Equity Grants in 2012” below.

CVR Energy conceptually approved a discretionary award of restricted stock units to Mr. Lipinski in an amount of up to $3,000,000 on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the CVR Energy compensation committee and approval of the CVR Energy board of directors, and the grant will be conditioned on Mr. Lipinski continuing to be employed by CVR Energy through December 31, 2013. To the extent awarded, the discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award. Due to the conditional nature of this award, it is not reported in the compensation tables below.

Perquisites

CVR Energy pays for a portion of the cost of medical insurance and life insurance for its named executive officers as it does for all non-union employees (except for certain supplemental life insurance). The total value of all perquisites and personal benefits provided to each of its named executive officers in 2012 was less than $10,000.

 

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Other Forms of Compensation

Each of the CVR Energy named executive officers has provisions in their respective employment agreements with CVR Energy for certain severance benefits in the event a termination of their employment under certain circumstances. These severance provisions are described below in “—Change-in-Control and Termination Payments” and were negotiated between the applicable named executive officers and CVR Energy.

Stock Retention Guidelines for Officers and Employees

In general, CVR Energy’s corporate governance guidelines require all of the officers and employees of CVR Energy or any of its affiliates who receive as compensation any share of its common stock (including shares of restricted stock or restricted stock units awarded pursuant to CVR Energy’s LTIP, and any other securities into which such restricted stock or restricted stock units are changed or for which such restricted stock or restricted stock units are exchanged) to retain at least 50% of such equity securities once they become vested for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) so long as such individual remains an officer or employee of CVR Energy.

Summary Compensation Table for Fiscal Year 2012

The following table sets forth a summary of total compensation paid by CVR Energy for 2012 and 2011 to its named executive officers that we also deem to be our named executive officers. The table shows amounts earned by the individuals for services rendered to CVR Energy in all capacities in which they served during the 2012 and 2011 years, as applicable. Please note that all information regarding equity compensation awards will not be applicable to us on a going-forward basis, as we will be responsible for maintaining our own LTIP, and CVR Energy will be responsible for the settlement of all costs related to equity awards that CVR Energy determines to award to its named executive officers. The amount set forth in the total column reflects the product of each respective named executive officer’s total compensation, without reference to which CVR Energy-affiliated entity that the individual was providing services for with respect to the compensation paid and does not necessarily reflect the amount of such named executive officer’s compensation that will be allocated to us pursuant to our services agreement with CVR Energy. For more information about this services agreement, see “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners—Services Agreement with CVR Energy.” For information about the amount of time we expect our named executive officers to devote to us during the first year following this offering, see “Management of CVR Refining, LP—Executive Officers and Directors.”

 

Name and Principal Position

   Year      Salary ($)      Stock
Awards ($)(1)
     Non-Equity
Incentive Plan
Compensation
($)(2)
     All Other
Compensation ($)(3)
     Total ($)(4)  

John J. Lipinski, Chief Executive Officer

     2012         950,000         11,589,180         2,375,000         25,105         14,939,285   
     2011         900,000         5,000,011         2,541,206         24,751         8,465,968   

Stanley A. Riemann, Chief Operating Officer

     2012         450,000         4,427,820         900,000         25,105         5,802,925   
     2011         425,000         1,487,518         960,011         24,751         2,897,280   

Susan M. Ball, Chief Financial Officer

     2012         281,189         1,542,448         239,004         16,869         2,079,510   

Edmund S. Gross, Senior Vice President and General Counsel

     2012         380,000         2,923,367         380,000         25,115         3,708,482   
     2011         362,000         1,086,003         408,852         24,769         1,881,624   

Robert W. Haugen, Executive Vice President, Refining Operations

     2012         290,000         1,273,352         348,000         19,829         1,931,181   
     2011         275,000         495,015         349,421         16,134         1,135,570   

 

(1)

Amounts in this column reflect the aggregate grant date fair value of restricted stock units awards originally granted to the named executive officers in August and December of 2012 pursuant to the CVR Energy LTIP, computed in accordance with FASB ASC Topic 718. The following assumptions were utilized in the calculation of awards granted in 2012: a per share CVR Energy common stock value of $29.26 for awards made on August 7, 2012 and $47.68 per share of CVR Energy common stock for awards made on

 

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December 28, 2012). In addition, this column reflects amounts also reported for each named executive officer that received restricted stock units in replacement for the cancelled restricted stock awards in 2012. The amounts with respect to the replacement awards are not the grant date fair value for the awards, as they are not new grants, but they reflect the incremental fair value of receiving a new type of award under FASB ASC Topic 718. The incremental accounting amount reflected for each named executive officer is as follows: $8,589,154 for Mr. Lipinski; $2,627,805 for Mr. Riemann; $576,374 for Ms. Ball; $2,123,344 for Mr. Gross; and $723,316 for Mr. Haugen.

(2) Amounts in this column reflect an estimate of the amounts that would be earned based upon meeting target levels pursuant to the CVR Energy PIP in respect of performance during 2012. We expect amounts earned under the CVR Energy PIP will be paid in the first quarter of the 2013 year. We expect that the amounts paid may exceed the target levels. We will disclose the final approved amounts within a Form 8-K at the time the amounts are paid.
(3) Amounts in this column for 2012 include the following: (a) a Company contribution under the CVR Energy 401(k) plan of $15,000 for each of Messrs. Lipinski, Riemann, Gross and Haugen and Ms. Ball; (b) $8,665 for Messrs. Lipinski and Riemann, $1,365 for Ms. Ball, $8,675 for Mr. Gross and $3,955 for Mr. Haugen in premiums paid by CVR Energy on behalf of the executive officer with respect to its executive life insurance program; and (c) $1,440 for Messrs. Lipinski, Riemann and Gross, $504 for Ms. Ball, and $874 for Mr. Haugen in premiums paid by CVR Energy on behalf of the executive officer with respect to its basic life insurance program.
(4) The total columns reflect an estimate of the amounts that may become earned pursuant to the CVR Energy PIP; these numbers may change when amounts are determined.

Grants of Plan-Based Awards in Fiscal Year 2012

The following table sets forth information concerning amounts that could be earned under the CVR Energy PIP with respect to the 2012 year, and all equity compensation awards that were granted pursuant to the CVR Energy LTIP during the 2012 year.

 

            Estimated Future Payouts Under
Non-Equity Incentive Plan Awards(1)
     All Other Stock Awards:
Number of Shares of
Stock or Units (#)
     Grant Date
Fair Value of
Stock Awards ($)(2)
 

Name

   Grant Date      Threshold
($)
     Target ($)      Maximum
($)
       

John J. Lipinski

     12/28/2012         593,750         2,375,000         4,156,250         62,920         3,000,026   

Stanley A. Riemann

     12/28/2012         225,000         900,000         1,575,000         37,752         1,800,015   

Susan M. Ball

     8/07/2012                  5,675         166,051   
     12/28/2012         59,751         239,004         418,257         16,779         800,023   

Edmund S. Gross

     12/28/2012         95,000         380,000         665,000         16,779         800,023   

Robert W. Haugen

     12/28/2012         104,400         348,000         591,600         11,536         550,036   

 

(1) Amounts in these columns reflect amounts that could have been earned by the CVR Energy named executive officers under the CVR Energy PIP in respect of 2012 performance at the threshold, target and maximum levels with respect to each performance measure. The performance measures and related goals set by the CVR Energy compensation committee for 2012 are described in “Compensation Discussion and Analysis” above, but actual amounts will be determined and paid within the first quarter of the 2013 year.
(2) Amounts in these columns reflect the grant date fair value of CVR Energy’s common stock (using a per share common stock value of $29.26 on August 7, 2012 and $47.68 per share on December 28, 2012) underlying the restricted stock unit awards made to the CVR Energy named executive officers pursuant to the CVR Energy LTIP during 2012, computed in accordance with FASB ASC Topic 718. All settlements will be paid in cash rather than in shares of CVR Energy common stock.

Employment Agreements

John J. Lipinski. On July 12, 2005, Coffeyville Resources LLC entered into an employment agreement with Mr. Lipinski, as chief executive officer, which was subsequently assumed by CVR Energy and amended and restated effective as of January 1, 2008. Mr. Lipinski’s employment agreement was amended and restated

 

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effective January 1, 2010 and subsequently amended and restated on January 1, 2011. The agreement has a rolling term of three years so that at the end of each month it automatically renews for one additional month, unless otherwise terminated by CVR Energy or Mr. Lipinski. Mr. Lipinski receives an annual base salary of $900,000 effective as of January 1, 2011. Mr. Lipinski is also eligible to receive a performance-based annual cash bonus with a target payment equal to 250% of his annual base salary to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy for each fiscal year. In addition, Mr. Lipinski is entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy.

The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure and also includes covenants relating to non-solicitation and non-competition that govern during his employment and thereafter for the period severance is paid and, if no severance is paid, for one year following termination of employment. In addition, Mr. Lipinski’s agreement provides for certain severance payments that may be due following the termination of his employment under certain circumstances, which are described below under “—Change-in-Control and Termination Payments.”

Susan M. Ball. Ms. Ball entered into her employment agreement with CVR Energy on July 27, 2012, which, effective as of August 7, 2012, governs her employment as CVR Energy’s Chief Financial Officer and Treasurer. Ms. Ball’s agreement terminates on August 7, 2015 unless terminated earlier as provided in the agreement. The employment agreement provides Ms. Ball with a base annual salary of $350,000 plus eligibility for a performance-based annual cash bonus with a target payment equal to 100% of her annual base salary to be based upon individual and/or performance criteria as established by the compensation committee of the board of directors of CVR Energy. In addition, the employment agreement entitles Ms. Ball to participate in such health, insurance, retirement and other employee benefit plans and programs as in effect from time to time on the same basis as other senior executives of CVR Energy.

Stanley A. Riemann, Edmund S. Gross and Robert W. Haugen. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Messrs. Riemann, Gross and Haugen, which were subsequently assumed by CVR Energy and amended and restated effective as of December 29, 2007. The agreements were amended and restated effective January 1, 2010 and subsequently amended and restated on January 1, 2011. The agreements with Messrs. Riemann, Gross and Haugen each have a term of three years that expire in January 2014, unless otherwise terminated earlier by either party to the agreement. The employment agreement provides for an annual base salary of $425,000 for Mr. Riemann, $362,000 for Mr. Gross and $275,000 for Mr. Haugen, effective as of January 1, 2011. Each executive officer is also eligible to receive a performance-based annual cash bonus to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy for each fiscal year. The target annual bonus percentages for these executive officers effective as of January 1, 2011 are as follows: Mr. Riemann (200%), Mr. Gross (100%) and Mr. Haugen (120%). These executives are also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. The agreements required the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure and also include covenants relating to non-solicitation and, except in the case of Mr. Gross, non-competition during their employment and for one year following termination of employment. In addition, the employment agreements provide for certain severance payments that may be due following the termination of employment under certain circumstances, which are described below under “—Change-in-Control and Termination Payments.”

 

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Equity Grants in 2012

The named executive officers each received grants of restricted stock unit awards pursuant to the CVR Energy LTIP in 2012. Each restricted stock unit granted to Ms. Ball in August of 2012 represents the right to receive, upon vesting, a cash payment equal to the lesser of $30 or the fair market value of a restricted share, as defined in the Transaction Agreement. The August grant to Ms. Ball is subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant and are also subject to immediate vesting under certain circumstances. The restricted stock units become immediately vested in the event of death, disability or retirement, and in certain circumstances in connection with a change in control. The terms disability, retirement and change in control are all defined in the CVR Energy’s long term incentive plan.

The December grants of restricted stock units represent the right to receive, upon vesting, a cash payment equal to the fair market value of one share of CVR Energy common stock at the vesting date, plus the cash value of all dividends that were declared and paid by CVR Energy during the vesting period for that award. The December restricted stock unit grants to Ms. Ball and Messrs. Gross and Haugen are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant. The December grants to Messrs. Lipinski and Riemann vest on the first anniversary of the grant date. Each of the December award grants are also subject to immediate vesting under certain circumstances. The restricted stock units become immediately vested in the event of death or disability, and in certain circumstances in connection with a change in control. The terms disability and change in control are defined in the CVR Energy’s long term incentive plan.

Outstanding Equity Awards at 2012 Fiscal Year-End

This table reflects outstanding restricted stock unit awards held by the CVR Energy named executive officers as of December 31, 2012.

 

     Stock Awards  

Named Executive Officer

   Number of Shares
or Units of Stock
That Have Not
Vested (#)(1)
    Market Value of
Shares or Units of
Stock That Have
Not Vested ($)(2)
 

John J. Lipinski

     74,177 (3)      2,225,310   
     74,111 (4)      2,223,330   
     177,968 (5)      5,339,040   
     62,920 (6)      3,000,026   

Stanley A. Riemann

     23,180 (3)      695,400   
     22,782 (4)      683,460   
     52,946 (5)      1,588,380   
     37,752 (6)      1,800,015   

Susan M. Ball

     3,709 (3)      111,270   
     3,590 (4)      107,700   
     10,732 (5)      321,960   
     5,675 (7)      170,250   
     16,779 (6)      800,023   

Edmund S. Gross

     19,703 (3)      591,090   
     15,239 (4)      457,170   
     38,654 (5)      1,159,620   
     16,779 (6)      800,023   

Robert W. Haugen

     5,795 (3)      173,850   
     5,435 (4)      163,050   
     17,619 (5)      528,570   
     11,536 (6)      550,036   

 

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(1) Represents shares of unvested restricted stock units held by the named executive officers as of December 31, 2012. The awards disclosed in the table above are subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change in Control and Termination Payments” below. Pursuant to the Transaction Agreement, shares of restricted stock units held by the named executive officers will, upon becoming vested in accordance with their terms, be converted into the right to receive, and will be settled by means of, a cash payment as provided in the Transaction Agreement.
(2) Amounts in this column reflect the market value of the shares of unvested restricted stock units outstanding and held by each named executive officer as of December 31, 2012, calculated (a) for purposes of the award dated December 28, 2012 by multiplying the number of unvested restricted stock units by the closing market price of CVR Energy’s common stock on the NYSE on such date ($48.79 per share), and (b) for purposes of all other awards by multiplying the number of unvested restricted stock units by $30 (the value on such dated under the Transaction Agreement).
(3) Represents award dated July 16, 2010, which will vest on July 16, 2013 .
(4) Represents award dated December 31, 2010, which will vest on December 31, 2013.
(5) Represents award dated December 30, 2011, which will in two equal tranches on December 30, 2013 and December 30, 2014.
(6) Represents award dated December 28, 2012, which will vest for Messrs. Lipinski and Riemann on December 28, 2013, and with respect to the remaining named executive officers, will vest in three equal tranches on each of December 28, 2013, December 28, 2014 and December 28, 2015.
(7) Represents award dated August 7, 2012, which will vest on three equal tranches on each of August 7, 2013, August 7, 2014 and August 7, 2015.

Equity Awards Vested During Fiscal Year 2012

This table reflects the portion of restricted stock unit awards granted pursuant to the CVR Energy LTIP that became vested during 2012.

 

     Equity Awards  

Named Executive Officer

   Number of Shares
or Units Acquired
on Vesting (#)
    Value Realized
on Vesting ($)(1)
 

John J. Lipinski

     74,177 (2)      2,225,310   
     88,984 (3)      2,669,520   
     74,111 (4)      2,223,330   

Stanley A. Riemann

     23,181 (2)      695,430   
     26,473 (3)      794,190   
     22,782 (4)      683,460   

Susan M. Ball

     3,709 (2)      111,270   
     5,089 (5)      152,670   
     5,366 (3)      160,980   
     3,590 (4)      107,700   

Edmund S. Gross

     19,703 (2)      591,090   
     5,089 (5)      152,670   
     19,328 (3)      579,840   
     15,240 (4)      457,200   

Robert W. Haugen

     5,795 (2)      173,850   
     8,810 (3)      264,300   
     5,435 (4)      163,050   

 

(1) For shares of restricted stock units that became vested during fiscal year 2012, the amounts reflected are calculated by multiplying the number of shares of CVR Energy’s common stock that became vested by $30 (the value on such dated under the Transaction Agreement).
(2) Represents award dated July 16, 2010.
(3) Represents award dated December 30, 2011.
(4) Represents award dated December 31, 2010.
(5) Represents award dated December 18, 2009.

 

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Change in Control and Termination Payments

Under the terms of the named executive officers’ employment agreements with CVR Energy, they may be entitled to severance and other benefits from CVR Energy following the termination of their employment with CVR Energy. The amounts of potential post-employment payments and benefits in the narrative and table below with respect to Messrs. Lipinski, Riemann, Gross and Haugen and Ms. Ball assume the triggering event took place on December 31, 2012, are based on salaries as of December 31, 2012 and assume the payment of bonuses at 100% of target. Pursuant to the services agreement that we will enter into with CVR Energy at the closing of this offering, we will be responsible only for the payment of severance and other benefits costs following the termination of employment of the executive officers that are expected to devote 100% of their time to managing our business, including Mr. Haugen.

John J. Lipinski. If Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement), then in addition to any accrued amounts, including any base salary earned but unpaid through the date of termination, any earned but unpaid annual bonus for completed fiscal years, any unused accrued paid time off and any unreimbursed expenses (“Accrued Amounts”), Mr. Lipinski is entitled to receive as severance (a) salary continuation for 36 months (b) a pro-rata bonus for the year in which termination occurs, based on actual results and (c) the continuation of medical, dental, vision and life insurance benefits (“Welfare Benefits”) for 36 months at active-employee rates or until such time as Mr. Lipinski becomes eligible for such benefits from a subsequent employer. In addition, if Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement) within one year following a change in control (as defined in his employment agreement) or in specified circumstances prior to and in connection with a change in control, Mr. Lipinski will receive 1/12 of his target bonus for the year of termination for each month of the 36 month period during which he is entitled to severance. A change in control (as defined in Mr. Lipinski’s employment agreement) occurred on May 7, 2012 upon the acquisition by certain affiliates of Icahn Enterprises of more than 30% of (i) the outstanding common stock of CVR Energy and (ii) the combined voting power of CVR Energy.

If Mr. Lipinski’s employment is terminated as a result of his disability, then in addition to any Accrued Amounts and any payments to be made to Mr. Lipinski under disability plan(s), Mr. Lipinski is entitled to (a) disability payments equal to, in the aggregate, Mr. Lipinski’s base salary as in effect immediately before his disability (the estimated total amount of this payment is set forth in the relevant table below) and (b) a pro-rata bonus for the year in which termination occurs, based on actual results. Such supplemental disability payments will be made in installments for a period of 36 months from the date of disability.

As a condition to receiving these severance payments and benefits, Mr. Lipinski must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. If Mr. Lipinski’s employment is terminated at any time by reason of his death, then in addition to any Accrued Amounts Mr. Lipinski’s beneficiary (or his estate) will be paid (a) the base salary Mr. Lipinski would have received had he remained employed through the remaining term of his employment agreement and (b) a pro-rata bonus for the year in which termination occurs, based on actual results. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski’s supplemental disability payments or the payments due to Mr. Lipinski’s beneficiary or estate by reason of his death. Mr. Lipinski will be required to cooperate in obtaining such insurance. Upon a termination by reason of Mr. Lipinski’s retirement after reaching age 62, in addition to any Accrued Amounts, Mr. Lipinski will receive (a) continuation of Welfare Benefits for 36 months at active-employee rates or until such time as Mr. Lipinski becomes eligible for such benefits from a subsequent employer, (b) provision of an office at CVR Energy’s headquarters and use of CVR Energy’s facilities and administrative support, each at CVR Energy’s expense, for 36 months and (c) a pro-rata bonus for the year in which termination occurs, based on actual results.

In the event that Mr. Lipinski is eligible to receive continuation of Welfare Benefits at active employee rates but is not eligible to continue to receive benefits under CVR Energy’s plans pursuant to the terms of such plans

 

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or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing Mr. Lipinski with such benefits at the same cost to CVR Energy as providing him with continued coverage under its plans. If such coverage cannot be obtained, CVR Energy will pay Mr. Lipinski on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had he continued participation in CVR Energy’s plans.

If any payments or distributions due to Mr. Lipinski would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be “cut back” only if that reduction would be more beneficial to him on an after-tax basis than if there was no reduction. The estimated total amounts payable to Mr. Lipinski (or his beneficiary or estate in the event of death) in the event of termination of employment under the circumstances described above are set forth in the table below. Mr. Lipinski would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by him voluntarily without good reason and not by reason of his retirement. The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure. The agreement also includes covenants relating to non-solicitation and noncompetition during Mr. Lipinski’s employment term, and thereafter during the period he receives severance payments or supplemental disability payments, as applicable, or for one year following the end of the term (if no severance or disability payments are payable).

Susan M. Ball, Stanley A. Riemann, Edmund S. Gross and Robert W. Haugen. Pursuant to their employment agreements as in effect on December 31, 2012, if the employment of Ms. Ball, Messrs. Riemann, Gross or Haugen, is terminated either by CVR Energy without cause and other than for disability or by the executive officer for good reason (as such terms are defined in their respective employment agreements), then these executive officers are entitled, in addition to any Accrued Amounts, to receive as severance (a) salary continuation for 12 months (18 months for Mr. Riemann), (b) a pro-rata bonus for the year in which termination occurs, based on actual results and (c) the continuation of Welfare Benefits for 12 months (18 months for Mr. Riemann) at active-employee rates or until such time as the executive officer becomes eligible for such benefits from a subsequent employer. In addition, if the employment of the named executive officers is terminated either by CVR Energy without cause and other than for disability or by the executives for good reason (as these terms are defined in their employment agreements) within one year following a change in control (as defined in their employment agreements) or in specified circumstances prior to and in connection with a change in control, they are also entitled to receive additional benefits. For Ms. Ball and Mr. Gross, the severance period and benefit continuation period is extended to 24 months and for Mr. Riemann would be extended to 30 months, and they will also receive monthly payments equal to 1/12 of their respective target bonuses for the year of termination during the 24 (or 30) month severance period. Mr. Haugen will receive monthly payments equal to 1/12 of his target bonus for the year of termination for 12 months. Upon a termination by reason of these executives’ employment upon retirement after reaching age 62, in addition to any Accrued Amounts, they will receive (a) a pro-rata bonus for the year in which termination occurs, based on actual results and (b) continuation of Welfare Benefits for 24 months at active-employee rates or until such time as they become eligible for such benefits from a subsequent employer. A change in control (as defined in the executive officers’ respective employment agreements) occurred on May 7, 2012 upon the acquisition by certain affiliates of Icahn Enterprises of more than 30% of (i) the outstanding common stock of CVR Energy and (ii) the combined voting power of CVR Energy.

In the event that Ms. Ball, Messrs. Riemann, Gross or Haugen are eligible to receive continuation of Welfare Benefits at active-employee rates but are not eligible to continue to receive benefits under CVR Energy’s plans pursuant to the terms of such plans or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing the executives with such benefits at the same cost to CVR Energy as providing them with continued coverage under CVR Energy’s plans. If such coverage cannot be obtained, CVR Energy will pay the executives on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had they continued participation in its plans.

 

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As a condition to receiving these severance payments and benefits, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction. These executive officers would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by him voluntarily without good reason and not by reason of retirement, death or disability. The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include covenants relating to non-solicitation and, except in the case of Mr. Gross, covenants relating to non-competition during their employment terms and for one year following the end of the terms.

The tables that follow reflects the severance that would have been paid to each of the CVR Energy named executive officers, had their employment been terminated under certain circumstances as of December 31, 2012 and assume the payment of bonuses at 100% of target.

 

    Cash Severance ($)     Benefit Continuation ($)  
    Death     Disability     Retirement     Termination without
Cause or with Good
Reason
    Death     Disability     Retirement     Termination
without Cause or
with Good
Reason
 
                      (1)     (2)                       (1)     (2)  

John J. Lipinski

    5,225,000        5,225,000        2,375,000        5,225,000        12,350,000        —          —          58,082        58,082        58,082   

Stanley A. Riemann

    —          —          900,000        1,575,000        4,275,000        —          —          38,721        29,041        48,402   

Susan M. Ball

    —          —          350,000        700,000        1,750,000            30,298        15,149        30,298   

Edmund S. Gross

    —          —          380,000        760,000        1,900,000        —          —          46,790        23,395        46,790   

Robert W. Haugen

    —          —          348,000        638,000        986,000        —          —          36,218        18,109        18,109   

 

(1) Severance payments and benefits in the event of termination without cause or resignation for good reason not in connection with a change in control.
(2) Severance payments and benefits in the event of termination without cause or resignation for good reason in connection with a change in control.

Each of the named executive officers has been granted shares of restricted stock units pursuant to CVR Energy’s LTIP.

The restricted stock units that were granted in December 2012 represent the right to receive, upon vesting, a cash payment equal to the fair market value of one share of CVR Energy common stock, plus the cash value of all dividends that were declared and paid by CVR Energy during the vesting period for that award. Restricted stock units granted prior to the December grants will represent the holder’s right to receive, upon vesting, a cash payment equal to the lesser of $30 or the fair market value of a restricted share, as defined in the Transaction Agreement. The restricted stock units are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant, or for certain grants made to Messrs. Lipinski and Riemann in December of 2012, on the first anniversary of the date of grant, subject to immediate vesting under certain circumstances.

The restricted stock units that were granted in December 2012 become immediately vested in the event of the relevant named executive officer’s death or disability. For Messrs. Lipinski and Riemann, the awards also become immediately vested if such executive is terminated other than for cause or such executive resigns for

 

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good reason. For each of the remaining named executive officers, (a) the awards become immediately vested in the event of any of the following: (i) such named executive officer’s employment is terminated other than for cause within the one-year period following a change in control of CVR Energy; (ii) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (iii) such named executive officer’s employment is terminated under certain circumstances prior to a change in control; and (b) if such executive is terminated other than for cause or such executive resigns for good reason in the absence of a change in control, then the portion of the award scheduled to vest in the year in which such event occurs becomes immediately vested and the remaining portion is forfeited. The terms disability, cause, good reason and change in control are all defined in the CVR Energy LTIP. A change in control (as defined in the CVR Energy LTIP) occurred on May 7, 2012 upon the acquisition by certain affiliates of Icahn Enterprises of more than 30% of (i) the outstanding common stock of CVR Energy and (ii) the combined voting power of CVR Energy.

The restricted stock units that were granted prior to December 2012 become immediately vested in the event of the relevant named executive officer’s death, disability or retirement, or in the event of any of the following: (a) such named executive officer’s employment is terminated other than for cause within the one-year period following a change in control of CVR Energy; (b) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (c) such named executive officer’s employment is terminated under certain circumstances prior to a change in control. The terms disability, retirement, cause, good reason and change in control are all defined in the CVR Energy LTIP. A change in control (as defined in the CVR Energy LTIP) occurred on May 7, 2012 upon the acquisition by certain affiliates of Icahn Enterprises of more than 30% of (i) the outstanding common stock of CVR Energy and (ii) the combined voting power of CVR Energy.

In addition, in the event that Messrs. Lipinski, Riemann, Gross or Haugen is terminated by CVR Energy without cause and other than for disability at any time on or following the date that the applicable executive officer reaches age 60, then such executive officer’s restricted stock units will vest immediately. As of the date of this Registration Statement, this acceleration provision would apply to Messrs. Lipinski, Riemann and Gross who were each at least 60 years old as of such date.

The following table reflects the value of accelerated vesting of the unvested restricted stock unit awards held by the CVR Energy named executive officers assuming the triggering event took place on December 31, 2012, and for purposes of the December 2012 awards is based on the closing price of the CVR Energy’s common stock as of such date, which was $48.79 per share, and for purposes of all other awards is based on a value of $30.00 per share in accordance with the Transaction Agreement.

 

     Value of Accelerated Vesting of Restricted Stock Unit Awards ($)  
     Death      Disability      Retirement      Termination without Cause
or with Good Reason
 
                          (1)      (2)  

John J. Lipinski

     12,857,547         12,857,547         9,787,680         9,787,680         12,857,547   

Stanley A. Riemann

     4,809,160         4,809,160         2,967,240         2,967,240         4,809,160   

Susan M. Ball

     1,529,827         1,529,827         711,180         —           1,529,827   

Edmund S. Gross

     3,026,527         3,026,527         2,207,880         2,207,880         3,026,527   

Robert W. Haugen

     1,428,341         1,428,341         865,500         —           1,428,341   

 

(1) Termination without cause or resignation for good reason not in connection with a change in control. The values included for Messrs. Lipinski, Riemann and Gross reflect accelerated vesting by reason of termination without cause after such executive has reached age 60.
(2) Termination without cause or resignation for good reason in connection with a change in control.

 

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Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to the lesser of $30 or the fair market value of a restricted share, as defined in the Transaction Agreement. The restricted stock units are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant, subject to immediate vesting under certain circumstances. The restricted stock units become immediately vested in the event of death, disability or retirement The terms disability, retirement, cause, good reason and change in control are all defined in the CVR Energy’s long term incentive plan.

Director Compensation

Officers, employees and directors of CVR Energy or its affiliates who serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Independent directors who are not officers, employees or directors of CVR Energy or its affiliates will receive compensation for attending meetings of our general partner’s board of directors and committees thereof. Independent directors will receive an annual director fee of $75,000, paid quarterly, and meeting fees of $1,000 per meeting. In addition, independent directors will also receive an additional annual retainer of $5,000 for serving as the chairman of any board committee, an additional annual retainer of $1,000 for serving on a board committee and will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors (and committees thereof) of our general partner and for other director-related education expenses. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

Reimbursement of Expenses of Our General Partner

Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf under the services agreement. See “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners—Services Agreement with CVR Energy” for a description of our services agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business and allocable to us. These expenses also include costs incurred by CVR Energy or its affiliates in rendering corporate staff and support services to us pursuant to the services agreement, including a pro rata portion of the compensation of CVR Energy’s executive officers who provide management services to us (based on the amount of time such executive officers devote to our business).

Our partnership agreement provides that our general partner will determine which of its and its affiliates’ expenses are allocable to us and the services agreement provides that CVR Energy will invoice us monthly for services provided thereunder. Our general partner may dispute the costs that CVR Energy charges us under the services agreement, but we will not be entitled to a refund of any disputed cost unless it is determined not to be a reasonable cost incurred by CVR Energy in connection with services it provided.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table presents information regarding beneficial ownership of our common units following this offering by:

 

   

our general partner;

 

   

each of our general partner’s directors (including all director nominees);

 

   

each of our general partner’s named executive officers;

 

   

each unitholder known by us to beneficially hold five percent or more of our outstanding units; and

 

   

all of our general partner’s executive officers and directors as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all units beneficially owned, subject to community property laws where applicable. Except as otherwise indicated, the business address for each of our beneficial owners is 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479.

 

Name of Beneficial Owner

   Common Units
to be Beneficially
Owned
     Percentage of
Total Common
Units to be
Beneficially
Owned(1)
 

CVR Refining GP, LLC(2)

     —           —     

CVR Energy, Inc.(3)

     127,600,000         86.4

John J. Lipinski(4)

     —           —     

Stanley A. Riemann

     —           —     

Susan M. Ball

     —           —     

Edmund S. Gross

     —           —     

Robert W. Haugen

     —           —     

Vincent J. Intrieri

     —           —     

Samuel Merksamer

     —           —     

Carl C. Icahn(5)

     —           —     

Daniel A. Ninivaggi

     —           —     

SungHwan Cho

     —           —     

Glenn R. Zander

     —           —     

Jon R. Whitney

     —           —     

Keith Cozza

     —           —     

Kenneth Shea

     —           —     

All directors and executive officers as a group (17 persons)

     —           —     

 

* Less than 1%
(1) Based on 147,600,000 common units outstanding following this offering.
(2) CVR Refining GP, LLC, a wholly owned subsidiary of CVR Refining Holdings, is our general partner and manages and operates our business and has a non-economic general partner interest.
(3) 127,587,540 of these common units will be owned of record by CVR Refining Holdings, LLC and 12,460 of these common units will be owned of record by CVR Refining Holdings Sub, LLC, each of which is an indirect wholly-owned subsidiary of CVR Energy. CVR Energy, Inc. is a publicly traded company. The directors of CVR Energy are Carl C. Icahn, Bob G. Alexander, SungHwan Cho, Vincent J. Intrieri, Samuel Merksamer, Stephen Mongillo, Daniel A. Ninivaggi, Glenn R. Zander, James M. Strock and John J. Lipinski. The table assumes the underwriters do not exercise their option to purchase 3,000,000 additional common units and such units are therefore issued to CVR Refining Holdings, LLC upon the option’s expiration. If such option is exercised in full, CVR Energy, Inc. will beneficially own 124,587,540 common units, or 84.4% of the total common units outstanding.
(4) Mr. Lipinski has indicated an interest in purchasing approximately $5 million of the common units being offering in this offering through our directed unit program, in which case Mr. Lipinski would directly own approximately 0.1% of our common units.

 

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(5) 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 approximately 2.7% of our common units. Mr. Icahn may be deemed to indirectly beneficially own any common units purchased by Icahn Enterprises or its affiliates for purposes of Section 13(d) of the Exchange Act. Mr. Icahn disclaims beneficial ownership of such common units for all other purposes.

The following table sets forth, as of November 1, 2012, the number of shares of common stock of CVR Energy owned by each of the named executive officers and directors of our general partner (including director nominees) and all directors and executive officers of our general partner as a group.

 

     Shares Beneficially
Owned as of
November 1, 2012
 

Name of Beneficial Owner

   Number      Percent(1)  

John J. Lipinski

     —          
—  
  

Stanley A. Riemann

     —           —     

Susan M. Ball

     —           —     

Edmund S. Gross

     —           —     

Robert W. Haugen

     —           —     

Vincent J. Intrieri

     —           —     

Samuel Merksamer

     —           —     

Carl C. Icahn(2)

     71,198,718         82

Daniel A. Ninivaggi

     —           —     

SungHwan Cho

     —           —     

Glenn R. Zander

     —           —     

Jon R. Whitney

     —           —     

Keith Cozza

     —           —     

Kenneth Shea

     —           —     

All directors and executive officers as a group (17 persons)

     71,198,718         82

 

(1) Percentage calculated based upon 86,831,050 shares of common stock outstanding as of November 1, 2012.
(2) Shares of common stock reflected as beneficially owned by Mr. Icahn are owned of record by IEP Energy LLC, a subsidiary of Icahn Enterprises L.P. Mr. Icahn may be deemed to indirectly beneficially own such shares for purposes of Section 13(d) of the Exchange Act. Mr. Icahn disclaims beneficial ownership of such shares for all other purposes.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, (i) CVR Energy, will indirectly own 127,600,000 common units, representing approximately 86.4% of our outstanding units (approximately 84.4% if the underwriters exercise their option to purchase additional common units in full) and (ii) our general partner will own a non-economic general partner interest in us that does not entitle it to receive distributions. In addition, the majority stockholder 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, in which case they would directly own approximately 2.7% of our common units.

Distributions and Payments to CVR Energy and its Affiliates

The following table summarizes the distributions and payments made or to be made by us to CVR Energy and its affiliates (including our general partner) in connection with the formation, offering of common units, ongoing operations and any liquidation of CVR Refining, LP. These distributions and payments were or will be determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

 

The consideration received by CVR Energy and its affiliates for our formation

  A non-economic general partner interest

 

   

100% of our limited partner interests

 

Redemption of Coffeyville Resources 9.0% Senior Secured Notes due 2012

  On October 23, 2012 CVR Refining, LLC and Coffeyville Finance Inc. sold an aggregate $500.0 million of senior notes and used the net proceeds therefrom to redeem the 9.0% Senior Secured Notes due 2015 issued by Coffeyville Resources.

Offering Stage

 

The consideration received by CVR Energy and its affiliates for the contribution of CVR Refining, LLC and cash

  127,600,000 common units issued immediately prior to the closing of this offering; and

 

   

we will also agree to undertake a public or private offering of common units in the future upon request by CVR Refining Holdings and use the proceeds thereof (net of underwriting or placement agency discounts fees and commissions, as applicable) to redeem an equal number of common units from CVR Refining Holdings as a distribution to reimburse CVR Refining Holdings for certain capital expenditures incurred with respect to the assets contributed to us.

 

Option units or proceeds from option units

  We will distribute to CVR Refining Holdings any net proceeds received from the underwriters exercise of their 30-day option to purchase up to an aggregate of 3,000,000 additional common units. If the underwriters do not exercise their option in full or at all, we will distribute the common units that would have been sold to the underwriters to CVR Refining Holdings.

 

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Repurchase of Coffeyville Resources 10.875% Senior Secured Notes due 2017

  We will use a portion of the net proceeds from the sale of              common units in this offering to repurchase the 10.875% Senior Secured Notes due 2017 issued by Coffeyville Resources.

Post-IPO Operational Stage

 

Distributions to CVR Energy and its subsidiaries

  We will generally make cash distributions to our unitholders, including CVR Refining Holdings, pro rata. Immediately following this offering, based on ownership of our common units at such time, CVR Energy and its subsidiaries will own approximately 86.4% of our common units (84.4% if the underwriters exercise their option to purchase additional common units in full) and would receive a pro rata percentage of the available cash that we distribute in respect thereof.

 

Payments to our general partner and its affiliates

  We will reimburse our general partner and its affiliates for all expenses incurred on our behalf. In addition, we will reimburse CVR Energy for certain operating expense and for the provision of various general and administrative services for our benefit under the services agreement.

Liquidation Stage

 

Liquidation

  Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with CVR Energy and CVR Partners

We entered into several agreements with CVR Partners and its affiliates in connection with CVR Partners’ initial public offering in April 2011 and CVR Partners’ formation in October 2007. The agreements govern the business relations among us and CVR Partners. We will also enter into several agreements with CVR Energy in connection with our initial public offering that will govern our management and business relationship with CVR Energy. These agreements were not the result of arm’s-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

Contribution Agreement

On December 31, 2012, we entered into a Contribution Agreement with CVR Refining Holdings and certain of its affiliates pursuant to which CVR Refining Holdings contributed CVR Refining, LLC to us and we assumed all liabilities (including unknown and contingent liabilities) associated with owning CVR Refining, LLC after its contribution to us. In addition, CVR Refining Holdings contributed a 0.01% limited partner interest in us to its wholly-owned subsidiary, CVR Refining Holdings Sub, LLC.

Reorganization Agreement

Prior to the closing of this offering, we will enter into a Reorganization Agreement, whereby 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 and excluding cash to be used to repurchase the 10.875% Senior Secured Notes due 2017 issued by Coffeyville Resources. If such amount of cash on hand at the closing of

 

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this offering exceeds $340 million, we will distribute the excess to Coffeyville Resources. In addition, pursuant to the Reorganization Agreement, we will (i) issue 127,587,540 common units to CVR Refining Holdings and 12,460 common units to CVR Refining Holdings Sub, LLC, (ii) issue any common units not purchased by the underwriters pursuant to their option to purchase additional common units, and distribute the net proceeds (after deducting discounts and commissions) from the exercise of such option, if any, to CVR Refining Holdings and (iii) agree to undertake an offering of common units in the future upon request by CVR Refining Holdings and will use the proceeds thereof (net of underwriting discounts and commissions) to redeem an equal number of common units from CVR Refining Holdings as a distribution to reimburse CVR Refining Holdings for certain capital expenditures incurred with respect to the assets contributed to us.

Intercompany Credit Facility

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 to be used to fund growth capital expenditures. See “Management Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities—Intercompany Credit Facility.”

Coke Supply Agreement

We entered into a pet coke supply agreement with CVR Partners in October 2007 pursuant to which we supply CVR Partners with pet coke. This agreement provides that we must deliver to CVR Partners during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100% of the pet coke produced at our Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CVR Partners is also obligated to purchase this annual required amount. If we produce more than 41,667 tons of pet coke during a calendar month, CVR Partners will have the option to purchase the excess at the purchase price provided for in the agreement. If CVR Partners declines to exercise its option, we may sell the excess to a third party.

The price that we receive pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received by CVR Partners for UAN (the “UAN-based price”), and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.

CVR Partners also pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. CVR Partners is entitled to offset any amount payable for the pet coke against any amount we owe under the feedstock and shared services agreement, which is described below. If CVR Partners fails to pay an invoice on time, it must pay interest on the outstanding amount payable at a rate of three percent above the prime rate.

In the event we deliver pet coke to CVR Partners on a short-term basis and such pet coke is off-specification on more than 20 days in any calendar year, the price for such pet coke will be adjusted to compensate CVR Partners and/or we will contribute funds in order to share the cost of the expenditures CVR Partners must make to modify its equipment to process the off-specification pet coke it received. If we determine that there will be a change in pet coke quality on a long-term basis, we will be required to provide CVR Partners with at least three years’ notice of such change. CVR Partners will then determine the appropriate changes necessary to its nitrogen fertilizer plant in order to process such off-specification pet coke. We will compensate CVR Partners for the cost of making such modifications and/or adjust the price of pet coke on a mutually agreeable commercially reasonable basis.

The terms of the pet coke supply agreement provide benefits to us as well as CVR Partners. The cost of the pet coke we supply to CVR Partners in most cases will be lower than the price CVR Partners otherwise would

 

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pay to third parties. The cost to CVR Partners will be lower both because the actual price paid will be lower and because CVR Partners will pay significantly reduced transportation costs (the pet coke is supplied by our adjacent facility and therefore does not involve freight or tariff costs). In addition, because the cost CVR Partners pays will be formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), CVR Partners will enjoy lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.

In return for us receiving a potentially lower price for pet coke in periods when the pet coke price is impacted by lower UAN prices, we enjoy the following benefits associated with the disposition of a low value by-product of the refining process: avoiding the capital cost and operating expenses associated with handling pet coke; enjoying flexibility in our crude slate and operations as a result of not being required to meet a specific pet coke quality; and avoiding the administration, credit risk and marketing fees associated with selling pet coke.

CVR Partners may be obligated to provide security for its payment obligations under the agreement if in our sole judgment there is a material adverse change in CVR Partners’ financial condition or liquidity position or in its ability to make payments. This security shall not exceed an amount equal to 21 times the average daily dollar value of pet coke CVR Partners purchases for the 90-day period preceding the date on which we give CVR Partners notice that we have deemed that a material adverse change in its financial condition, liquidity position or in its ability to make payments has occurred. Unless otherwise agreed to by us and CVR Partners, CVR Partners can provide the security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If CVR Partners does not provide such security, we may require CVR Partners to pay for future deliveries of pet coke on a cash-on-delivery basis, failing which we may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days’ prior written notice. Additionally, CVR Partners may terminate the agreement within 60 days of providing such security, so long as it provides five days’ prior written notice to us.

The agreement has an initial term of 20 years (ending October 2027), which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within the applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of CVR Partners’ operations at its nitrogen fertilizer plant or at our Coffeyville refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.

Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements.

The agreement contains an obligation for each party to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain affiliates.

Our pet coke sales price per ton sold averaged $28, $11, and $22 for the years ended December 31, 2011, 2010 and 2009, respectively. Our total sales to CVR Partners were approximately $11.4 million, $4.3 million and $6.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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Feedstock and Shared Services Agreement

We entered into a feedstock and shared services agreement with CVR Partners in October 2007 and an amended and restated feedstock and shared services agreement in April 2011 in connection with CVR Partners’ initial public offering. Under this agreement, we agreed with CVR Partners to exchange feedstock and other services. The feedstocks and services are utilized in the respective production processes of our Coffeyville refinery and CVR Partners’ nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas.

Pursuant to the feedstock agreement, we and CVR Partners have an obligation to transfer excess hydrogen to one another. CVR Partners is only obligated to provide hydrogen to us upon demand if the hydrogen is not required for operation of CVR Partners’ fertilizer plant, as determined in a commercially reasonable manner based upon CVR Partners’ current or anticipated operational needs. The feedstock agreement provides hydrogen supply and pricing terms for sales of hydrogen by both parties. The price we pay for purchases of hydrogen from CVR Partners is structured to make CVR Partners whole as if it had used the hydrogen sold to us to produce ammonia. After extended periods of time and in excess of certain quantity thresholds, the price we pay reverts to a UAN pricing structure to make CVR Partners whole, as if CVR Partners had produced UAN for sale. Pricing for sales of hydrogen by us to CVR Partners is based off of the price of natural gas. The hydrogen sales that we and CVR Partners make to each other are netted on a monthly basis, and we or CVR Partners will be paid to the extent that either of us sells more hydrogen than purchased in any given month. For the years ended December 31, 2011, 2010 and 2009, we recorded approximately $14.2 million, $0.1 million and $0.8 million, respectively, in cost of product sold for net monthly purchases of hydrogen from CVR Partners. For the years ended December 31, 2011, 2010 and 2009, we recorded net monthly sales for transfers of excess hydrogen to CVR Partners of $1.0 million, $1.8 million and $1.6 million, respectively.

Additionally, we are obligated, upon reasonable notice or request of CVR Partners, to use commercially reasonable efforts to provide high-pressure steam to CVR Partners for the commencement or recommencement of its nitrogen plant operations or for use at its Linde air separation plant. CVR Partners is similarly obligated to provide high-pressure steam to us that it produces but does not require after we provide reasonable notice requesting the same. For the years ended December 31, 2011 and 2010 we purchased $0.2 million and $0.1 million of high-pressure steam from CVR Partners, and during the year ended December 31, 2009 CVR Partners purchased $0.2 million of high-pressure steam from us.

CVR Partners is also obligated to make available to us any nitrogen produced by the Linde air separation plant that is not required for the operation of CVR Partners’ nitrogen fertilizer plant, as determined by CVR Partners in a commercially reasonable manner. The price for the nitrogen is based on a cost of $0.035 cents per kilowatt hour, as adjusted to reflect changes in the CVR Partners electric bill. For the years ended December 31, 2011, 2010 and 2009, we paid CVR Partners approximately $1.5 million, $0.8 million and $0.8 million, respectively, for nitrogen.

The agreement also provides that both we and CVR Partners must deliver instrument air to one another in some circumstances. CVR Partners must make instrument air available for our purchase at a minimum flow rate, to the extent produced by its Linde air separation plant and available to CVR Partners. The price for the instrument air is $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in the CVR Partners electric bill. To the extent that instrument air is not available from the Linde air separation plant but is available from us, we are required to make instrument air available to CVR Partners for purchase at a price of $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in our electric bill.

The agreement provides a mechanism pursuant to which CVR Partners may transfer a tail gas stream (which is otherwise flared) to us through a pipe between our Coffeyville refinery and CVR Partners’ nitrogen fertilizer

 

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plant, which we installed. CVR Partners agreed to pay us the cost of installing the pipe over the first three years (commencing in 2011) and in the fourth year provide an additional 15% to cover the cost of capital.

With respect to oxygen requirements, CVR Partners is obligated to provide oxygen produced by its Linde air separation plant and made available to CVR Partners to the extent that such oxygen is not required for operation of the nitrogen fertilizer plant. The oxygen is required to meet certain specifications and is sold to us at a fixed price.

The agreement also addresses the means that we and CVR Partners obtain natural gas. Currently, natural gas is delivered to both CVR Partners’ nitrogen fertilizer plant and our Coffeyville refinery pursuant to a contract between us and Atmos Energy Corp. (“Atmos”). Under the amended and restated feedstock and shared services agreement, CVR Partners reimburses us for natural gas transportation and natural gas supplies purchased on CVR Partners’ behalf. At our request, or at the request of CVR Partners, in order to supply CVR Partners with natural gas directly, both parties will be required to use their commercially reasonable efforts to (i) add CVR Partners as a party to the current contract with Atmos or reach some other mutually acceptable accommodation with Atmos whereby both we and CVR Partners would each be able to receive, on an individual basis, natural gas transportation service from Atmos on similar terms and conditions as set forth in the current contract, and (ii) would each be able to purchase natural gas supplies on its own account.

The agreement also addresses the allocation of various other feedstocks, services and related costs between us and CVR Partners. Sour water, water for use in fire emergencies, finished product tank capacity, costs associated with security services, and costs associated with the removal of excess sulfur are all allocated between us and CVR Partners by the terms of the agreement. The agreement also requires CVR Partners to reimburse us for utility costs related to a sulfur processing agreement between us and Tessenderlo Kerley, Inc. (“Tessenderlo Kerley”). CVR Partners has a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both our and CVR Partners’ existing agreements with Tessenderlo Kerley are allocated equally between us except in certain circumstances.

The parties may temporarily suspend the provision of feedstocks or services pursuant to the terms of the agreement if repairs or maintenance are necessary on applicable facilities. Additionally, the agreement imposes minimum insurance requirements on the parties and their affiliates.

The agreement has an initial term of 20 years (ending October 2027) and will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at CVR Partners’ nitrogen fertilizer plant or our Coffeyville refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding, or otherwise becomes insolvent.

Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.

 

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Raw Water and Facilities Sharing Agreement

We entered into a raw water and facilities sharing agreement with CVR Partners in October 2007 which (i) provides for the allocation of raw water resources between our Coffeyville refinery and CVR Partners’ nitrogen fertilizer plant and (ii) provides for the management of the water intake system (consisting primarily of a water intake structure, water pumps, meters and a short run of piping between the intake structure and the origin of the separate pipes that transport the water to each facility) which draws raw water from the Verdigris River for both our Coffeyville refinery and CVR Partners’ nitrogen fertilizer plant. This agreement provides that a water management team consisting of one representative from each party to the agreement will manage the Verdigris River water intake system. The water intake system is owned and operated by us. The agreement provides we and CVR Partners have an undivided one-half interest in the water rights which will allow the water to be removed from the Verdigris River for use at our Coffeyville refinery and CVR Partners’ nitrogen fertilizer plant.

The agreement provides that CVR Partners’ nitrogen fertilizer plant and our Coffeyville refinery are entitled to receive sufficient amounts of water from the Verdigris River each day to enable them to conduct their businesses at their appropriate operational levels. However, if the amount of water available from the Verdigris River is insufficient to satisfy the operational requirements of both facilities, then such water shall be allocated between the two facilities on a prorated basis. This prorated basis will be determined by calculating the percentage of water used by each facility over the two calendar years prior to the shortage, making appropriate adjustments for any operational outages involving either of the two facilities.

Costs associated with operation of the water intake system and administration of water rights are also allocated on a prorated basis, calculated by us based on the percentage of water used by each facility during the calendar year in which such costs are incurred. However, in certain circumstances, such as where one party bears direct responsibility for the modification or repair of the water pumps, one party will bear all costs associated with such activity. Additionally, CVR Partners must reimburse us for electricity required to operate the water pumps on a prorated basis that is calculated monthly.

We or CVR Partners can terminate the agreement by giving the other party at least three years’ prior written notice. Between the time that notice is given and the termination date, we are required to cooperate with CVR Partners to allow CVR Partners to build its own water intake system on the Verdigris River to be used for supplying water to CVR Partners’ nitrogen fertilizer plant. We are required to grant easements and access over our property so that CVR Partners can construct and utilize such new water intake system, provided that no such easements or access over our property shall have a material adverse effect on our business or operations at the Coffeyville refinery. CVR Partners will bear all costs and expenses for such construction if it is the party that terminated the original water sharing agreement. If we terminate the original water sharing agreement, CVR Partners may either install a new water intake system at its own expense, or require us to sell the existing water intake system to CVR Partners for a price equal to the depreciated book value of the water intake system as of the date of transfer.

Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the Coffeyville refinery or the nitrogen fertilizer plant, as applicable, in each case subject to applicable consent requirements. The parties may obtain injunctive relief to enforce their rights under the agreement. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.

 

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The term of the agreement is perpetual unless (1) the agreement is terminated by either party upon three years’ prior written notice in the manner described above or (2) the agreement is otherwise terminated by the mutual written consent of the parties.

Cross-Easement Agreement

We entered into a cross-easement agreement with CVR Partners in October 2007 and an amended and restated cross-easement agreement in April 2011. The purpose of the agreement is to enable both us and CVR Partners to access and utilize each other’s land in certain circumstances in order to operate our respective businesses. The agreement grants easements for the benefit of both parties and establishes easements for operational facilities, pipelines, equipment, access and water rights, among other easements. The intent of the agreement is to structure easements that provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party’s property.

The agreement provides that facilities located on each party’s property will generally be owned and maintained by the party owning such property; provided, however, that in certain specified cases where a facility that benefits one party is located on the other party’s property, the benefited party will have the right to use, and will be responsible for operating and maintaining, the subject facility.

The easements granted under the agreement are non-exclusive to the extent that future grants of easements do not interfere with easements granted under the agreement. The duration of the easements granted under the agreement will vary, and some will be perpetual. Easements pertaining to certain facilities that are required to carry out the terms of CVR Partners’ other agreements with us will terminate upon the termination of such related agreements.

The agreement contains an obligation to indemnify, defend and hold harmless the other party against liability arising from negligence or willful misconduct by the indemnifying party. The agreement also requires the parties to carry minimum amounts of employer’s liability insurance, commercial general liability insurance, and other types of insurance. If either party transfers its fee simple ownership interest in the real property governed by the agreement, the new owner of the real property will be deemed to have assumed all of the obligations of the transferring party under the agreement, except that the transferring party will retain liability for all obligations under the agreement which arose prior to the date of transfer.

Environmental Agreement

We entered into an environmental agreement with CVR Partners in October 2007 that provides for certain indemnification and access rights in connection with environmental matters affecting our Coffeyville refinery and CVR Partner’s nitrogen fertilizer plant. A supplement to the agreement was entered into by us and CVR Partners in February 2008 in connection with the execution of a related comprehensive pet coke management plan and the transfer by us to CVR Partners of certain property related to the agreement. We and CVR Partners also agreed to supplement the agreement in July 2008 in order to amend and restate the comprehensive pet coke management plan.

To the extent that one party’s property experiences environmental contamination due to the activities of the other party and the contamination is known at the time the agreement was entered into, the contaminating party is required to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for expenses incurred in connection with implementing such measures.

To the extent that liability arises from environmental contamination that is caused by us but is also commingled with environmental contamination caused by CVR Partners, we may elect in our sole discretion and at our own cost and expense to perform government-mandated environmental activities relating to such liability,

 

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subject to certain conditions and provided that we will not waive any rights to indemnification or compensation otherwise provided for in the agreement.

The agreement also addresses situations in which a party’s responsibility to implement such government-mandated environmental activities as described above may be hindered by the property-owning party’s creation of capital improvements on the property. If a contaminating party bears such responsibility but the property-owning party desires to implement a planned and approved capital improvement project on its property, the parties must meet and attempt to develop a soil management plan together. If the parties are unable to agree on a soil management plan 30 days after receiving notice, the property-owning party may proceed with its own commercially reasonable soil management plan. The contaminating party is responsible for the costs of disposing of hazardous materials pursuant to such plan.

If the property-owning party needs to do work that is not a planned and approved capital improvement project but is necessary to protect the environment, health, or the integrity of the property, other procedures will be implemented. If the contaminating party still bears responsibility to implement government-mandated environmental activities relating to the property and the property-owning party discovers contamination caused by the other party during work on the capital improvement project, the property-owning party will give the contaminating party prompt notice after discovery of the contamination and will allow the contaminating party to inspect the property. If the contaminating party accepts responsibility for the contamination, it may proceed with government-mandated environmental activities relating to the contamination and it will be responsible for the costs of disposing of hazardous materials relating to the contamination. If the contaminating party does not accept responsibility for such contamination or fails to diligently proceed with government-mandated environmental activities related to the contamination, then the contaminating party must indemnify and reimburse the property-owning party upon the property-owning party’s demand for costs and expenses incurred by the property-owning party in proceeding with such government-mandated environmental activities.

Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the Coffeyville refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement has a term of at least 20 years or for so long as the feedstock and shared services agreement is in force, whichever is longer. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain of its affiliates.

The agreement also provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement was entered into or that occur subsequent to the execution of the agreement to the extent such contamination or releases are identified in reasonable detail before October 2012. If one party causes such contamination or release on the other party’s property, the latter party must notify the contaminating party, and the contaminating party must take steps to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for the costs associated with doing such work.

The agreement also grants each party reasonable access to the other party’s property for the purpose of carrying out obligations under the agreement. However, both parties must keep certain information relating to the environmental conditions on the properties confidential. Furthermore, both parties are prohibited from investigating soil or groundwater conditions except as required for government-mandated environmental activities, in responding to an accidental or sudden contamination of certain hazardous materials, or in connection with implementation of CVR Partners’ comprehensive pet coke management plan.

A comprehensive pet coke management plan that was subsequently entered into pursuant to the agreement establishes procedures for the management of pet coke and the identification of significant pet coke-related contamination. Also, the parties agreed to indemnify and defend one another and each other’s affiliates against

 

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liabilities arising under the pet coke management plan or relating to a failure to comply with or implement the pet coke management plan.

Omnibus Agreement

We will agree to be bound by the omnibus agreement with our general partner, CVR Energy, CVR Partners, and CVR Partners’ general partner. This agreement was originally entered into by CVR Partners, CVR Energy and certain other parties in October 2007 and amended and restated in connection with CVR Partners’ initial public offering.

Under the omnibus agreement we will agree to, and will cause our controlled affiliates not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy continues to own at least 50% of CVR Partners’ outstanding units and CVR Energy continues to control our general partner. The restrictions do not apply to:

 

   

any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by CVR Energy’s board of directors, as applicable; however, if at any time we complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to CVR Partners for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to CVR Partners separately from the acquired business or package of assets;

 

   

engaging in any fertilizer restricted business subject to the offer to CVR Partners described in the immediately preceding bullet point pending CVR Partners’ determination whether to accept such offer and pending the closing of any offers the we accept;

 

   

engaging in any fertilizer restricted business if CVR Partners has previously advised CVR Energy that CVR Partners has elected not to acquire such business; or

 

   

acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any fertilizer restricted business.

Services Agreement with CVR Energy

We will enter into a services agreement with CVR Energy concurrently with the closing of this offering. Under this agreement, we and our general partner will obtain certain management and other services from CVR Energy to conduct our day-to-day business operations. CVR Energy will provide us with the following services under the agreement, among others:

 

   

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

 

   

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

 

   

management of our property and the property of our subsidiaries in the ordinary course of business;

 

   

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

 

   

managing or overseeing litigation and administrative or regulatory proceedings, establishing appropriate insurance policies for us and providing us with safety and environmental advice;

 

 

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recommending the payment of distributions; and

 

   

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

As payment for services provided under the agreement, we, our general partner, or our subsidiaries, must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other than administrative personnel, who provide us services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide us services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges. We must pay CVR Energy within 15 days for invoices it submits under the agreement.

We and our general partner are not required to pay any compensation, salaries, bonuses or benefits to any of CVR Energy’s employees who provide services to us or our general partner on a full-time or part-time basis; CVR Energy will continue to pay their compensation. However, personnel performing the actual day-to-day business and operations at the petroleum refinery plant level will be employed directly by us and our subsidiaries, and we will bear all personnel costs for these employees.

Either CVR Energy or our general partner will be allowed to temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. CVR Energy will also have the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation does not relieve CVR Energy from its obligations under the agreement. Beginning one year after the completion of this offering, either CVR Energy or our general partner may terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, our general partner may terminate the agreement immediately if CVR Energy becomes bankrupt, or dissolves and commences liquidation or winding-up.

In order to facilitate the carrying out of services under the agreement, we, on the one hand, and CVR Energy and its affiliates, on the other, will grant one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.

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

 

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Trademark License Agreement

In connection with this offering, we will enter into a trademark license agreement pursuant to which CVR Energy will grant us a non-exclusive, non-transferrable license to use the Coffeyville Resources trademarks in connection with our business. Pursuant to this agreement, we will agree to use the marks only in the form and manner and with appropriate legends as prescribed from time to time by CVR Energy, and will agree that the nature and quality of the business that uses the marks will conform to standards currently applied by CVR Energy. Either party will be able to terminate the license with 60 days’ prior notice.

Registration Rights Agreement

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, a wholly-owned subsidiary of CVR Refining Holdings, pursuant to which we may be required to register the sale of the common units they hold. Under the registration rights agreement, Icahn Enterprises, CVR Refining Holdings and CVR Refining Holdings Sub, LLC will have the right to request that we register the sale of common units held by them on their behalf on six occasions, including requiring us to make available shelf registration statements permitting sales of common units into the market from time to time over an extended period, and may require us to undertake a public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, Icahn Enterprises, CVR Refining Holdings and CVR Refining Holdings Sub, LLC and their permitted transferees will have the ability to exercise certain piggyback registration rights with respect to their securities if we elect to register any of our equity interests. The registration rights agreement will also include provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of our common units held by Icahn Enterprises, CVR Refining Holdings and CVR Refining Holdings Sub, LLC and any permitted transferee will be entitled to these registration rights.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners (including Coffeyville Resources and CVR Energy), on the one hand, and us and our public unitholders, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage us in a manner that it believes is not adverse to our interest. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner and its owners, on the one hand, and us and our public unitholders, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

   

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

 

   

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

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of the board of our general partner or from the holders of a majority of the outstanding units as described above. If our general partner does not seek approval from the conflicts committee or from holders of units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. See “Management—Management of CVR Refining, LP” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

We rely primarily on the executive officers of our general partner, who also serve as the senior management team of CVR Energy and its affiliates, to manage most aspects of our business and affairs.

We rely primarily on the executive officers of our general partner, who also serve as the senior management team of CVR Energy and its affiliates, to manage most aspects of our business and affairs.

 

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Although we will enter into a services agreement with CVR Energy upon the closing of this offering, under which we compensate CVR Energy for the services of its management, CVR Energy’s management is not required to devote any specific amount of time to our business and may devote a substantial majority of their time to the business of CVR Energy rather than to our business. Moreover, following the one year anniversary of this offering, CVR Energy can terminate the services agreement at any time, subject to a 180-day notice period. In addition, the executive officers of CVR Energy, including its chief executive officer, chief operating officer, chief financial officer and general counsel, will face conflicts of interest if decisions arise in which we and CVR Energy have conflicting points of view or interests.

Our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, guaranteeing debt of its affiliates and those activities incidental to its ownership of interests in us. However, except as provided in our partnership agreement, affiliates of our general partner (which includes CVR Energy) are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

The owners of our general partner are not required to share business opportunities with us.

Our partnership agreement provides that the owners of our general partner are permitted to engage in separate businesses which directly compete with us and are not required to share or communicate or offer any potential business opportunities to us even if the opportunity is one that we might reasonably have pursued. The partnership agreement provides that the owners of our general partner will not be liable to us or any unitholder for breach of any duty or obligation by reason of the fact that such person pursued or acquired for itself any business opportunity.

Neither our partnership agreement nor any other agreement requires CVR Energy or its affiliates to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. CVR Energy’s directors and officers must make these decisions in accordance with the fiduciaries duties they owe to the stockholders of CVR Energy, including Carl C. Icahn and certain of his affiliates, which may be contrary to our interests.

The officers and certain directors of our general partner who are also officers or directors of CVR Energy have fiduciary duties to CVR Energy and to its stockholders, including its majority stockholder, Icahn Enterprises, that may cause them to pursue business strategies that disproportionately benefit CVR Energy or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us (such as CVR Energy) in exercising certain rights under our partnership agreement.

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 in its capacity as our 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, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to the units it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership or amendment of the partnership agreement.

 

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Our general partner has limited its liability in the partnership agreement and replaced default fiduciary duties with contractual corporate governance standards set forth therein, thereby restricting the remedies available to our unitholders for actions that, without such replacement, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, 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 acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

 

   

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners 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; and

 

   

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. See “—Fiduciary Duties.”

Actions taken by our general partner may affect the amount of cash distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of the board of directors of our general partner regarding such matters as:

 

   

the expenses associated with being a public company and other general and administrative expenses;

 

   

the creation of reserves;

 

   

interest expense and other financing costs related to current and future indebtedness;

 

   

amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings; and

 

   

the issuance of additional units.

Our partnership agreement permits us to borrow funds to make a distribution, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

Our general partner and its affiliates are not required to own any of our common units. If our general partner’s affiliates were to sell all or substantially all of their common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself than our common unitholders.

Upon the closing of this offering, affiliates of our general partner will own the majority of our outstanding units, but there is no requirement that they continue to do so. The general partner and its affiliates are permitted to sell all of their common units. In addition, the current owners of our general partner may sell the general

 

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partner interest or their interest in the general partner to an unrelated third party. If neither the general partner nor its affiliates owned any of our common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself than our common unitholders.

We will reimburse our general partner and its affiliates, including CVR Energy, for expenses.

We will reimburse our general partner and its affiliates, including CVR Energy, for costs incurred in managing and operating us, including overhead costs incurred by CVR Energy in rendering corporate staff and support services to us. Our partnership agreement provides that the board of directors of our general partner will determine in good faith the expenses that are allocable to us and that reimbursement of overhead to CVR Energy as described above is fair and reasonable to us. The services agreement will not contain any cap on the amount we may be required to pay pursuant to this agreement. See “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners—Services Agreement with CVR Energy.”

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 equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed; and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. 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 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.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s length negotiations. Our general partner will determine, in good faith, the terms of any such future transactions.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets, other than its interest in us. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

 

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We may choose not to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us in this offering have been retained by our general partner or its affiliates. Attorneys, independent accountants and others who perform services for us in the future will be selected by our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Except in limited circumstances, our general partner has the power and authority to conduct our business without limited partner approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 

   

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into equity securities of the partnership, and the incurring of any other obligations;

 

   

the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

   

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person (subject in certain circumstances to approval by the limited partners);

 

   

the use of our assets for any purpose consistent with the terms of the partnership agreement, including the financing of the conduct of our and our subsidiaries’ operations, the lending of funds to other persons; the repayment or guarantee of obligations of us or any of our subsidiaries and the making of capital contributions to us or any of our subsidiaries;

 

   

the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

   

the distribution of partnership cash;

 

   

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

   

the maintenance of insurance for our benefit and the benefit of our partners;

 

   

the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

 

   

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

   

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

   

the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the interests in our partnership from, or requesting that trading be suspended on, any such exchange;

 

   

the purchase, sale or other acquisition or disposition of our equity securities, or the issuance of additional options, rights, warrants, appreciation rights tracking, profit and phantom interests and other derivative instruments relating to, convertible into or exchangeable for our securities; and

 

   

the entering into of agreements with any of its affiliates, including any agreement to render services to us or to itself in the discharge of its duties as our general partner.

 

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See “The Partnership Agreement” for information regarding the voting rights of common unitholders.

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owners. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests. The following is a summary of:

 

   

the default fiduciary duties under by the Delaware Act;

 

   

the standards contained in our partnership agreement that replace the default fiduciary duties; and

 

   

certain rights and remedies of limited partners contained in the Delaware Act.

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith”, meaning that it believed its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards reduce the obligations to which our general partner would otherwise be held.

 

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  If our general partner does not seek approval from the conflicts committee of its board of directors or the unitholders, excluding any units owned by our general partner or its affiliates, and its board of directors approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. These standards reduce the obligations to which our general partner would otherwise be held.

 

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of it and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement.

In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. See “Description of The Common Units—Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign the partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment 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. Thus,

 

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our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. See “The Partnership Agreement—Indemnification.”

Related Party Transactions

We have adopted policies for the review, approval and ratification of transactions with related persons. At the discretion of our general partner’s board of directors, a proposed related party transaction may generally be approved by the board in its entirety, or by a “conflicts committee” meeting the definitional requirements for such a committee under our partnership agreement.

 

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DESCRIPTION OF THE COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the rights and privileges of holders of our common units to partnership distributions, see “How We Make Cash Distributions” and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, see “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

 

   

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

   

special charges for services requested by a holder of a common unit; and

 

   

other similar fees or charges.

There is no charge to unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

   

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

   

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

   

gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

Our common units have been approved for listing on the NYSE under the symbol “CVRR.”

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Annex A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

   

with regard to distributions of cash, see “How We Make Cash Distributions”;

 

   

with regard to the duties of our general partner, see “Conflicts of Interest and Fiduciary Duties”;

 

   

with regard to the authority of our general partner to manage our business and activities, see “Management—Management of CVR Refining, LP”;

 

   

with regard to the transfer of common units, see “Description of The Common Units—Transfer of Common Units”; and

 

   

with regard to allocations of taxable income and taxable loss, see “Material Tax Consequences.”

Organization and Duration

We were organized in September 2012 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is limited to engaging in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law.

Although our general partner has the ability to cause us and our subsidiary to engage in activities other than those related to the petroleum refining business and activities now or hereafter customarily conducted in conjunction with this business, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Common unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.” For a discussion of our general partner’s right to contribute capital to maintain its and its affiliates’ percentage interest if we issue partnership interests, see “—Issuance of Additional Partnership Interests.”

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require the approval of a majority of the common units.

 

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At the closing of this offering, CVR Energy will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment which requires a unit majority by virtue of its 86.4% indirect ownership of our common units.

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. The holders of a majority of the common units (including common units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

 

Issuance of additional partnership interests

No approval right. See “—Issuance of Additional Partnership Interests.”

 

Amendment of our partnership agreement

Certain amendments may be made by our general partner without the approval of the common unitholders. Other amendments generally require the approval of a unit majority. See “—Amendment of Our Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority under certain circumstances. See “—Merger, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. See “—Termination and Dissolution.”

 

Continuation of our partnership upon dissolution

Unit majority. See “—Termination and Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2022. See “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2/3% of the outstanding common units, including common units held by our general partner and its affiliates. See “—Withdrawal or Removal of Our General Partner.”

 

Transfer of the general partner interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. See “—Transfer of General Partner Interests.”

 

Transfer of ownership interest in our general partner

No approval required at any time. See “—Transfer of Ownership Interests in Our General Partner.”

 

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If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of such units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

   

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

   

brought in a derivative manner on our behalf;

 

   

asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

   

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

   

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware or other court located in the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

The Delaware Act generally provides that a limited partner does not participate in the control of the business within the meaning of the Delaware Act by virtue of possessing or exercising the right or power to admit, remove or retain the general partner, amend the partnership agreement or certificate of limited partnership, or cause the taking or refraining from taking of any action with respect to such other matters as are stated in the partnership agreement. However, if a court were to determine that the right, or exercise of the right, by the limited partners as a group to take any action under the partnership agreement constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner.

This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

 

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Under the Delaware Act, a limited partnership may not make a distribution to a limited partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries currently conduct business in Arkansas, Iowa, Kansas, Missouri, Nebraska, Oklahoma, Texas and South Dakota. We and our current subsidiaries or any future subsidiaries may conduct business in other states in the future. Maintenance of our limited liability as a member of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. We have attempted to limit our liability for the obligations of CVR Refining, LLC by structuring it as a limited liability company.

If, by virtue of our membership interest in CVR Refining, LLC or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or liability company statute, or that the right, or exercise of the right by the limited partners as a group, to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our quarterly cash distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, have special voting rights to which the common units are not entitled or are senior in right of distribution to the common units. 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.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain its and its affiliates’

 

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percentage interest, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or any partner, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

(1) enlarge the obligations of any limited partner or general partner without its consent, unless approved by at least a majority of the type or class of partner interests so affected;

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion;

(3) change certain of the terms under which we can be dissolved; or

(4) change the term of the partnership.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding common units, voting together as a single class (including common units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately 86.4% of the outstanding common units (approximately 84.4% if the underwriters exercise their option to purchase additional common units in full). In addition, if Icahn Enterprises and Carl C. Icahn purchase 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 this offering, our general partner and its affiliates will own approximately 89.2% of our common units (or approximately 87.1% if the underwriters’ option to purchase additional common units is exercised in full).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any other partner to reflect:

 

   

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

   

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

   

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed);

 

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed;

 

   

an amendment that our general partner determines to be necessary or appropriate for the creation, authorization, or issuance of additional partnership interests or rights to acquire partnership interests, as otherwise permitted by our partnership agreement;

 

   

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

   

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

   

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by us of activities permitted by our partnership agreement;

 

   

a change in our fiscal year or taxable year and related changes;

 

   

mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance subject to the terms of the partnership agreement; or

 

   

any other amendments substantially similar to any of the matters described above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any partner if our general partner determines that those amendments:

 

   

do not adversely affect in any material respect the partners considered as a whole or any particular class of partners;

 

   

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

   

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

   

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of common units under the provisions of our partnership agreement; or

 

   

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for U.S. federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding common units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of our limited partners.

 

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Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove the general partner or call a meeting of unitholders, must be approved by the affirmative vote of partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger or consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or other partners, including any duty to act in good faith or in the best interest of us or the other partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our common units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us into a new limited liability entity or merge us into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

(1) the election of our general partner to dissolve us, if approved by the holders of common units representing a unit majority;

(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

(3) the entry of a decree of judicial dissolution of our partnership; or

 

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(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4), the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of common units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

   

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

   

neither our partnership nor our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units excluding common units held by our general partner and its affiliates (including CVR Energy), and by giving 90 days’ written notice and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2022, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the unitholders if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest without the approval of the unitholders. See “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding units voting as a single class may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. See “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding units. The ownership of more than 33 1/3% of the outstanding common units by our general partner and its affiliates (including Coffeyville Resources) gives them the ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own

 

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approximately 86.4% of the outstanding common units (approximately 84.4% if the underwriters exercise their option to purchase additional common units in full). In addition, if Icahn Enterprises or its affiliates purchase 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 this offering, our general partner and its affiliates will own, upon completion of the offering, approximately 89.2% of our common units (or approximately 87.1% if the underwriters’ option to purchase additional common units is exercised in full).

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of the general partner interest. Under all other circumstances where our general partner withdraws or is removed, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due to the general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove CVR Refining GP as our general partner or otherwise change management. See “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of common units, that person or group loses voting rights on all of its common units. This loss of voting rights does not apply in certain circumstances. See “—Voting Rights.”

Call Right

If at any time our general partner and its affiliates own more than 95% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by public unitholders, as of a record date to be selected by our general partner, on at least 10 but not more

 

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than 60 days’ notice. Immediately following this offering the only class of limited partner interest outstanding will be the common units, and affiliates of our general partner will own 86.4% of the total outstanding common units (approximately 84.4% if the underwriters exercise their option to purchase additional common units in full). In addition, if Icahn Enterprises or its affiliates purchase 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 this offering, our general partner and its affiliates will own approximately 89.2% of our common units (or approximately 87.1% if the underwriters’ option to purchase additional common units is exercised in full). 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%.

The purchase price in the event of such an acquisition will be the greater of:

(1) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; or

(2) the average of the daily closing prices of the limited partner interests over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed.

As a result of our general partner’s right to purchase outstanding common units, a holder of common units may have its common units purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The U.S. federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. See “Material Tax Consequences—Disposition of Common Units.”

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

   

obtain proof of the nationality, citizenship or other related status of our limited partner (and their owners, to the extent relevant); and

 

   

permit us to redeem the common units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the board to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers, or in order to reverse an adverse determination that has occurred regarding such maximum rates, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us or our current or future subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

   

obtain proof of the U.S. federal income tax status of our partner (and their owners, to the extent relevant); and

 

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permit us to redeem the common units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by the general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders who are record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited. Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, a direct or subsequently approved transferee of our general partner or their affiliates, or, upon the approval by the general partner, any other unitholder, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner or Assignee

Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions. By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records.

Indemnification

Under our partnership agreement we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings:

(1) our general partner;

 

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(2) any departing general partner;

(3) any affiliate of our general partner or any departing general partner;

(4) any person who is or was a director, officer, fiduciary, trustee, manager or managing member of us or our subsidiaries, our general partner or any departing general partner or any of our general partner’s or any departing general partner’s affiliates;

(5) any person who is or was serving as a director, officer, fiduciary, trustee, manager or managing member of another person owing a fiduciary duty to us or our subsidiary at the request of a general partner or any departing general partner;

(6) any person who controls, or has previously controlled, our general partner; or

(7) any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for (1) all direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of our general partner, to perform services for us or for the general partner in the discharge of its duties to us) and (2) all other expenses reasonably allocable to us or otherwise incurred by our general partner in connection with operating our business (including expenses allocated to our general partner by its affiliates). Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available a report containing our unaudited financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with tax information reasonably required for federal and state income tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

 

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In addition, CVR Energy will have full and complete access to any records relating to our business, and our general partner will cause its officers and independent accountants to be available to discuss our business and affairs with CVR Energy’s officers, agents and employees.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his/her interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

(1) a current list of the name and last known address of each record holder;

(2) copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

(3) information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13 of the Exchange Act); and

(4) any other information regarding our affairs that our general partner determines is just and reasonable.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners’ trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units sold by our general partner or any of its affiliates (including CVR Refining Holdings) if an exemption from the registration requirements is not otherwise available. We will not be required to effect more than two registrations pursuant to this provision in any twelve-month period, and our general partner can defer filing a registration statement for up to six months if it determines that this would be in our best interests due to a pending transaction, investigation or other event. We have also agreed that, if we at any time propose to file a registration statement for an offering of partnership interests for cash, we will use all commercially reasonable efforts to include such number of partnership interests in such registration statement as any of our general partner or any of its affiliates shall request. We are obligated to pay all expenses incidental to these registrations, other than underwriting discounts and commissions. The registration rights in our partnership agreement are applicable with respect to our general partner and its affiliates after it ceases to be a general partner for up to two years following the effective date of such cessation. In addition, 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. See “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

Upon the completion of this offering, there will be 147,600,000 common units outstanding, 127,600,000 of which will be owned by CVR Refining Holdings and its affiliates, assuming the underwriters do not exercise their option to purchase additional common units; if they exercise such option in full, CVR Refining Holdings and its affiliates will own 124,600,000 common units. The sale of these common units could have an adverse impact on the price of our common units or on any trading market that may develop. Additionally, 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.

The 20,000,000 common units sold in this offering (or 23,000,000 common units if the underwriters exercise their option to purchase additional common units in full) will generally be freely transferable without restriction or further registration under the Securities Act. However, any common units held by an “affiliate” of ours (including Icahn Enterprises and its affiliates) may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from the registration requirements of the Securities Act pursuant to Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1% of the total number of the class of securities outstanding; or

 

   

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 by our affiliates are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned common units for at least six months, would be entitled to sell those common units under Rule 144 without regard to the volume, manner of sale and notice requirements of Rule 144 so long as we comply with the current public information requirement for the next six months after the six-month holding period expires.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to, and market price of, common units then outstanding. See “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates (including CVR Refining Holdings) have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold if an exemption from the registration requirements is not otherwise available. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years after it ceases to be a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the applicable registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Our general partner and its affiliates also may sell their units in private transactions at any time, subject to compliance with applicable 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. Under this agreement, Icahn Enterprises, CVR Refining Holdings and CVR Refining Holdings Sub, LLC will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they holds, subject to

 

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certain limitations. 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, as applicable. See “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners—Registration Rights Agreement.”

We, CVR Refining Holdings, our general partner, and the directors and executive officers of our general partner have agreed not to sell any common units until 180 days after the date of this prospectus, subject to certain exceptions. See “Underwriters” for a description of these lock-up provisions.

In addition, we intend to file a registration statement on Form S-8 under the Securities Act to register 11,070,000 common units issuable under our long-term incentive plan. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Units issued under our long-term incentive plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to Rule 144 limitations applicable to affiliates.

 

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MATERIAL TAX CONSEQUENCES

This section summarizes the material U.S. federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed U.S. Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to CVR Refining, LP and CVR Refining, LLC.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), whose functional currencies are the U.S. dollar and who hold common units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult such unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences that are particular to that unitholder resulting from ownership or disposition of its common units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our common units and the prices at which such common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which might be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of 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) (please see “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please see “—Disposition of Common Units—Allocations Between Transferors and Transferees”); (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please see “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”) and (iv) whether the deduction related to U.S. production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “—Tax Treatment of Operations—Deduction for U.S. Production Activities”).

Partnership Status

A partnership is not a taxable entity for federal income tax purposes and incurs no U.S. federal income tax liability. Instead, as described below, each of our unitholders will take into account his respective share of our items of income, gain, loss and deduction in computing his U.S. federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not give rise to income or gain taxable to such unitholder unless the amount of cash distributed to the unitholder exceeds the unitholder’s adjusted tax basis in his common units.

 

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Section 7704 of the Internal Revenue Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, development, mining, production, processing, refining, transportation, storage and marketing of any natural resource including crude oil and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon the factual representations made by us and our general partner regarding the composition of our income and the other representations set forth below, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and our partnership and limited liability company subsidiaries will be disregarded as entities separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

(i) Neither we nor any of our partnership or limited liability company subsidiaries has elected or will elect to be treated as a corporation for federal income tax purposes;

(ii) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code;

(iii) our business activities and operations and those of our subsidiaries will be operated in the manner described in this prospectus; and

(iv) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributing that stock to our unitholders in liquidation of their common units. This deemed contribution and liquidation should not result in the recognition of taxable income to our unitholders and us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for U.S. federal income tax purposes.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Accordingly, our taxation as a corporation would materially reduce our cash distributions to unitholders and thus would likely substantially reduce the value of our common units. In addition, any distribution made to a unitholder would be treated as (i) taxable dividend income to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in our common units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

 

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Limited Partner Status

Unitholders who are admitted as limited partners of CVR Refining, LP, as well as unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of common units, will be treated as partners of CVR Refining, LP for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of short sales, please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

Tax Consequences of Unit Ownership

Basis of Common Units. A unitholder’s tax basis in its common units initially will be the amount it paid for those common units plus its initial share of our nonrecourse liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities and (ii) decreased, but not below zero, by distributions to it, by its share of our losses, any decreases in its share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized.

Flow-Through of Taxable Income. Subject to the discussion below under “—Entity-Level Collections” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Treatment of Distributions. Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the unitholder’s tax basis in its common units, in which case the unitholder will recognize gain taxable in the manner described below under “—Disposition of Common Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease the unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Common Units.”

A non-pro rata distribution of money or property (including a deemed distribution described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for an allocable portion of the non-pro rata distribution. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income in an amount equal to the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing through the record date for distributions for the period ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income that will be 50% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of

 

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taxable income to cash distributions to a unitholder will increase. These estimates are based upon the assumption that earnings from operations will approximate the forecasted annual distribution on all common units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

(i) the earnings from operations exceed the amount required to make the forecasted annual distribution on all common units, yet we only distribute the forecasted annual distribution on all common units; or

(ii) we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Limitations on Deductibility of Losses. A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its common units and (ii) in the case of a unitholder that is an individual, estate, trust or certain type of closely-held corporation, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its common units reduced by (i) any portion of that basis attributable to the unitholder’s share of our liabilities, (ii) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (iii) any amount of money the unitholder borrows to acquire or hold its common units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the common units for repayment.

A unitholder subject to the basis and at risk limitations must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of common units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used.

In addition to the basis and at risk limitations, passive activity loss limitations generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future, and will not be available to offset a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of passive income we generate may be deducted in full when he disposes of all of its common units in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

 

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Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

(i) interest on indebtedness properly allocable to property held for investment;

(ii) our interest expense attributed to portfolio income; and

(iii) the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income. Such term generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder, we are authorized to treat the payment as a distribution of cash to the relevant unitholder. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction. In general, our items of income, gain, loss and deduction will be allocated amongst our unitholders in accordance with their percentage interests in us. Although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our common units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) its relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins LLP is of the opinion that, with the exception of the issues described in

 

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“—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be treated as having disposed of those common units. If so, such unitholder 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. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those common units would not be reportable by the unitholder, and (ii) any cash distributions received by the unitholder as to those common units would be fully taxable, possibly as ordinary income.

Due to lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of our common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their common units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for alternative minimum tax.

Tax Rates. Beginning January 1, 2013, the highest marginal U.S. federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts applies for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or is a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election. We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our common units under Section 743(b) of the Code. The Section 743(b) adjustment separately applies to each purchaser of common units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us.

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of common units due to lack of controlling authority. Because a

 

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unitholder’s tax basis for its common units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of common units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocate to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please see “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to a primary offering of new common units will be borne by our unitholders holding interests in us prior to any such offering. Please see “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please see “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts we incur will be treated as syndication expenses.

Deduction for U.S. Production Activities. Subject to the limitations on the deductibility of losses discussed above and the limitations discussed below, unitholders will be entitled to a deduction, herein referred to as the

 

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Section 199 deduction, equal to 9% of the lesser of (i) our qualified production activities income that is allocated to such unitholder or (ii) the unitholder’s taxable income, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

A unitholder’s otherwise allowable Section 199 deduction for each taxable year is reduced by 3% of the least of (i) the oil related qualified production activities income of the taxpayer for the taxable year, (ii) the qualified production activities income of the taxpayer for the taxable year, or (iii) the taxpayer’s taxable income for the taxable year (determined without regard to any Section 199 deduction). For this purpose, the term “oil related qualified production activities income” means the qualified production activities income attributable to the production, refining, processing, transportation, or distribution of oil, gas, or any primary production thereof. We expect that most or all of our qualified production activities income will consist of oil related qualified production activities income.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates

 

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of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Recent Legislative Developments. The present 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 interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing 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. Please read “—Partnership Status.” Any modification to the 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.

Disposition of Common Units

Recognition of Gain or Loss. A unitholder will be required to recognize gain or loss on a sale of common units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the common units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a common unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of common units will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to Section 751 Assets that we own, primarily depreciation recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a common unit and may be recognized even if there is a net taxable loss realized on the sale of a common unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of common units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

 

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Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

(i) a short sale;

(ii) an offsetting notional principal contract; or

(iii) a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements. A unitholder who sells or purchases any common units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

 

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Constructive Termination. We will be considered to have terminated our partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 will result in us filing two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure, the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs, notwithstanding two partnership tax years. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of common units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have a negative impact on the value of the common units. Please see “—Tax Consequences of Unit Ownership—Section 754 Election.”

If necessary to preserve the uniformity of our common units, our partnership agreement permits our general partner to take positions in filing our tax returns even when contrary to a literal application of regulations like the one described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. The general partner does not anticipate needing to take such positions, but if they were necessary, Vinson & Elkins L.L.P. would be unable to opine as to validity of such filing positions in the absence of direct and controlling authority.

A unitholder’s basis in common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss” and “—Tax Consequences of Unit Ownership—Section 754 Election.” The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our common units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

 

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Non-resident aliens and non-U.S. corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a non-U.S. corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the non-U.S. corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the non-U.S. corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A non-U.S. unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a non-U.S. unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business resulting from its investment in us.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS.

Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the common units. The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies

 

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against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(i) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(ii) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(iii) the amount and description of common units held, acquired or transferred for the beneficial owner; and

(iv) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.

Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

State, Local, Non-U.S. and Other Tax Consequences

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property in Arkansas, Iowa, Kansas, Missouri, Nebraska, Texas and South Dakota. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

 

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It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns that may be required of it.

 

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INVESTMENT IN CVR REFINING, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

   

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

   

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

   

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” meaning it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above and IRAs.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

Plan fiduciaries contemplating a purchase of common units are encouraged to consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement with respect to the common units being offered, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. are acting as representatives, and for whom Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Barclays Capital Inc., UBS Securities LLC, and Jefferies & Company, Inc. are acting as joint bookrunning managers, the following respective amounts of common units:

 

Underwriter

   Number
of Common Units
 

Credit Suisse Securities (USA) LLC

  

Citigroup Global Markets Inc.

  

Barclays Capital Inc.

  

UBS Securities LLC

  

Jefferies & Company, Inc. 

  

J.P. Morgan Securities LLC

  

Macquarie Capital (USA) Inc.

  

Simmons & Company International

  
  

 

 

 

Total

     20,000,000   
  

 

 

 

The underwriting agreement provides that the underwriters are obligated to purchase all of the common units in the offering if any are purchased, other than those units covered by the underwriters’ option to purchase additional units described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to 3,000,000 additional common units at the initial public offering price less the underwriting discounts and commissions. If any common units are purchased pursuant to this option, the underwriters will severally purchase the common units in approximately the same proportion as set forth in the table above.

The underwriters propose to offer the common units initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of up to $         per share. After the initial public offering the representatives may change the public offering price and concession.

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.

The following table summarizes the compensation we will pay (including a structuring fee of $         million, or $         million if the underwriters exercise their option to purchase additional units in full, payable by us to Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc.):

 

    Per Unit     Total  
    Without
option to
purchase
additional units
    With
option to
purchase
additional units
    Without
option to
purchase
additional units
    With
option to
purchase
additional units
 

Underwriting Discounts and Commissions paid by us

  $                  $                  $                  $               

 

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We will pay a structuring fee equal to 0.5% of the gross proceeds of this offering, including the gross proceeds from any exercise of the underwriters’ option to purchase additional units, but excluding the proceeds from the sale of any common units to Icahn Enterprises or its affiliates,to Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. This structuring fee will compensate Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. for providing advice regarding the capital structure of our partnership, the terms of the offering, the terms of our partnership agreement and the terms of certain other agreements between us and our affiliates.

We estimate that the expenses of the offering, not including the underwriting discounts and commissions and the structuring fee, will be approximately $3.5 million. The underwriters have agreed to reimburse us for a portion of the estimated expenses in an amount equal to up to $2.5 million, or up to $2.875 million if the underwriters option to purchase additional common units is exercised in full.

Our common units have been approved for listing on the NYSE under the symbol “CVRR.” In order to meet one of the requirements for listing the common units on the NYSE, the underwriters have undertaken to sell lots of 100 or more units to a minimum of 400 beneficial holders. The representatives have informed us that they do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the number of common units being offered.

We, our general partner, our general partner’s directors and executive officers and CVR Refining Holdings have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any of our common units or securities convertible into or exchangeable or exercisable for any of our common units, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common units, whether any of these transactions are to be settled by delivery of our common units or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids.

 

   

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

   

Over-allotment involves sales by the underwriters of common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units that they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the

 

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number of units in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing units in the open market.

 

   

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through the over-allotment option. If the underwriters sell more units than could be covered by their exercise of the over-allotment option, which is the equivalent of a naked short position, the position can only be closed out by buying units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

   

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

 

   

In passive market making, market makers in our common units who are underwriters or prospective underwriters may, subject to limitations, make bids for or purchases of our common units until the time, if any, at which a stabilizing bid is made.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result the price of our common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to us and to persons and entities with relationships to us, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships to the issuer. The underwriters and their respective affiliates may also communicate independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiation between us and the representatives. Among the factors to be considered in determining the initial public offering price of the common units, in addition to prevailing market conditions, will be our historical performance, estimates of our business potential and earnings prospects, an assessment of our management and the consideration of the above factors in relation to the current market valuation of companies in related businesses or which are comparable to us. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

 

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Directed Unit Program

At our request, the underwriters have reserved up to 7.5% of the common units being offered by this prospectus for sale at the initial public offering price to directors, officers and employees of CVR Refining, our general partner, CVR Energy and its subsidiaries, and Icahn Enterprises and its subsidiaries and affiliates. John J. Lipinski, the Chief Executive Officer and President of our general partner has indicated an interest in purchase approximately $5 million of the common units being offered in this offering through this program. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, an underwriter of this offering, through a directed unit program. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same terms as the other common units. Participants in the directed unit program shall be subject to a 120-day lock-up with respect to any units sold to them pursuant to that program. This lock-up will have similar restrictions and an identical extension provision to the lock-up agreements described above. Any units sold in the directed unit program to our general partner’s directors or executive officers shall be subject to the lock-up agreements described above.

Electronic Distribution

A prospectus in electronic format will be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of common units to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the EEA

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

   

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

   

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

   

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

 

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provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognized collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is for distribution only to persons:

 

  (1) if our partnership is a CIS and is marketed by a person who is an authorized person under FSMA, (i) who are investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS Promotion Order) or (ii) who are high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

  (2) (i) who have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order), (ii) falling within Article 49(2)(a) to (d) (high net worth companies, unincorporated associations, etc.) of the Financial Promotion Order, or (iii) outside the United Kingdom; and

 

  (3) in both cases (1) and (2) above, whom it may otherwise lawfully be communicated or caused to be communicated (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person must not act or rely on this document or any of its contents.

No person may communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) received by it in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus other than in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the

 

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Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Capital Investment Act (Vermôgensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 2 no. 4 of the German Capital Investment Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

 

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LEGAL MATTERS

The validity of the common units and certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham  & Watkins LLP.

EXPERTS

The combined financial statements of CVR Refining, LP as of December 31, 2011 and 2010, and for each of the years in the three-year period ended December 31, 2011, and the balance sheet of CVR Refining, LP as of September 17, 2012, have been included herein (and in the registration statement) in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Gary-Williams Energy Corporation as of and for the year ended December 31, 2010, included in this Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Gary-Williams Energy Corporation and subsidiaries as of December 31, 2009 and for each of the years in the two-year period ended December 31, 2009, have been included herein (and in the registration statement) in reliance upon the report of KPMG LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to the common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including any exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC.

 

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INDEX TO FINANCIAL STATEMENTS

 

CVR REFINING, LP

  

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

  

Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2012

     P-1   

Unaudited Pro Forma Condensed Combined Statement of Operations for the Nine Months Ended September  30, 2012

     P-2   

Unaudited Pro Forma Condensed Combined Statement of Operations for the Nine Months Ended September 30, 2011

     P-3   

Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December  31, 2011

     P-4   

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

     P-5   

AUDITED BALANCE SHEET

  

Report of Independent Registered Public Accounting Firm

     F-1   

Balance Sheet as of September 17, 2012

     F-2   

Notes to the Financial Statement

     F-3   

CVR REFINING, LP COMBINED FINANCIAL STATEMENTS

  

UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

  

Condensed Combined Balance Sheets as of September 30, 2012 and December 31, 2011

     F-4   

Condensed Combined Statements of Operations for the Nine Months Ended September 30, 2012 and  2011

     F-5   

Condensed Combined Statement of Changes in Divisional Equity for the Nine Months Ended September  30, 2012

     F-6   

Condensed Combined Statements of Cash Flows for the Nine Months Ended September 30, 2012 and  2011

     F-7   

Notes to Unaudited Condensed Combined Financial Statements

     F-8   

AUDITED COMBINED FINANCIAL STATEMENTS

  

Report of Independent Registered Public Accounting Firm

     F-30   

Combined Balance Sheets as of December 31, 2011 and 2010

     F-31   

Combined Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

     F-32   

Combined Statements of Changes in Divisional Equity for the Years Ended December  31, 2011, 2010 and 2009

     F-33   

Combined Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

     F-34   

Notes to Combined Financial Statements

     F-35   

GARY-WILLIAMS ENERGY CORPORATION

  

UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

  

Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010

     F-73   

Consolidated Statements of Operations for the Nine Months Ended September 30, 2011 and 2010

     F-74   

Consolidated Statements of Changes in Retained Earnings for the Nine Months Ended September  30, 2011 and 2010

     F-75   

Consolidated Statements of Comprehensive Income for the Nine Months Ended September  30, 2011 and 2010

     F-76   

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010

     F-77   

Notes to Unaudited Consolidated Financial Statements

     F-78   

 

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Index to Financial Statements

AUDITED CONSOLIDATED FINANCIAL STATEMENTS

  

Report of Independent Auditors

     F-90   

Report of Independent Auditors

     F-91   

Consolidated Balance Sheets as of December 31, 2010 and 2009

     F-92   

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008

     F-94   

Consolidated Statements of Shareholder’s Equity for the Years Ended December  31, 2010, 2009 and 2008

     F-95   

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December  31, 2010, 2009 and 2008

     F-96   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008

     F-97   

Notes to Consolidated Financial Statements

     F-99   

 

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Index to Financial Statements

CVR Refining, LP

Unaudited Pro Forma Condensed Combined Balance Sheet

As of September 30, 2012

(dollars in thousands)

 

    Historical     Pro Forma
Adjustments
        Pro Forma   

ASSETS

       

Current assets:

       

Cash and cash equivalents

  $ 79,550      $ 500,000      a   $ 340,000   
      (9,000   b  
      (478,679   c  
      (20,117   c  
      59,390      e  
      500,000      f  
      (31,000   g  
      (248,032   h  
      (12,112   h  

Accounts receivable, net of allowance for doubtful accounts of $1,766 at September 30, 2012 and on a pro forma basis, including $938 from affiliates at September 30, 2012 and on a pro forma basis

    273,746        —            273,746   

Inventories

    494,744        —            494,744   

Prepaid expenses and other current assets including $916 due from affiliates at September 30, 2012 and on a pro forma basis

    24,698        900      b     21,380   
      (3,339   c  
      (879   h  

Insurance receivables

    1,233        —            1,233   
 

 

 

   

 

 

     

 

 

 

Total current assets

    873,971        257,132          1,131,103   

Property, plant and equipment, net

    1,319,768        —            1,319,768   

Deferred financing costs, net

    13,045        8,100      b     13,004   
      (5,054   c  
      (3,087   h  

Insurance receivable

    4,076        —            4,076   

Other long-term assets, including $473 due from affiliates at September 30, 2012 and on a pro forma basis

    1,805        —            1,805   
 

 

 

   

 

 

     

 

 

 

Total assets

  $ 2,212,665      $ 257,091        $ 2,469,756   
 

 

 

   

 

 

     

 

 

 

LIABILITIES AND DIVISIONAL EQUITY/PARTNERS’ CAPITAL

       

Current liabilities:

       

Capital lease obligations

  $ 1,054      $ —          $ 1,054   

Accounts payable, including $152 due to affiliates at September 30, 2012 and on a pro forma basis

    354,029        —            354,029   

Personnel accruals

    13,243        —            13,243   

Accrued taxes other than income taxes

    21,312        —            21,312   

Accrued expenses and other current liabilities, including $179 due to affiliates at September 30, 2012 and on a pro forma basis

    147,972        (20,117   c     115,743   
      (12,112   h  
 

 

 

   

 

 

     

 

 

 

Total current liabilities

    537,610        (32,229       505,381   

Long-term liabilities:

       

Long-term debt and capital lease obligations, net of current portion

    725,937        500,000      a     551,456   
      (447,050   c  
      (6,604   d  
      (222,750   h  
      1,923      i  

Accrued environmental liabilities, net of current portion

    1,331        —            1,331   

Other long-term liabilities, including $1,360 due to affiliates at September 30, 2012 and on a pro forma basis

    10,093        —            10,093   
 

 

 

   

 

 

     

 

 

 

Total long-term liabilities

    737,361        (174,481       562,880   
 

 

 

   

 

 

     

 

 

 

Commitments and contingencies

       

Divisional equity

    937,694        (40,022   c     —     
      6,604      d  
      (29,248   h  
      59,390      e  
      (1,923   i  
      (932,495   j  

PRO FORMA PARTNERS’ CAPITAL

       

Common unitholders—public, 20,000,000 units issued and outstanding

    —          500,000      f     469,000   
      (31,000   g  

Common unitholders—parent, 127,600,000 units issued and outstanding

    —          932,495      j     932,495   

General Partner Interest

    —          —        k     —     
 

 

 

   

 

 

     

 

 

 

Total divisional equity/partners’ capital

    937,694        463,801          1,401,495   
 

 

 

   

 

 

     

 

 

 

Total liabilities and divisional equity/partners’ capital

  $ 2,212,665      $ 257,091        $ 2,469,756   
 

 

 

   

 

 

     

 

 

 

The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

 

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CVR Refining, LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Nine Months Ended September 30, 2012

(dollars in thousands)

 

     Historical     Pro Forma
Adjustments
           Pro Forma  

Net sales

   $ 6,465,571      $ —           $ 6,465,571   

Operating costs and expenses:

         

Cost of product sold (exclusive of depreciation and amortization)

     5,191,032        —             5,191,032   

Direct operating expenses (exclusive of depreciation and amortization)

     253,176        —             253,176   

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     67,554        —             67,554   

Depreciation and amortization

     80,355             80,355   
  

 

 

   

 

 

      

 

 

 

Total operating costs and expenses

     5,592,117        —             5,592,117   
  

 

 

   

 

 

      

 

 

 

Operating income

     873,454        —             873,454   
  

 

 

   

 

 

      

 

 

 

Other income (expense):

         

Interest expense and other financing costs

     (56,044     24,019        a         (31,679
       346        b      

Realized loss on derivatives, net

     (80,426     —             (80,426

Unrealized loss on derivatives, net

     (196,980     —             (196,980

Other income, net

     723        —             723   
  

 

 

   

 

 

      

 

 

 

Total other income (expense)

     (332,727     24,365           (308,362
  

 

 

   

 

 

      

 

 

 

Net income

   $ 540,727      $ 24,365         $ 565,092   
  

 

 

   

 

 

      

 

 

 
Common unitholders’ interest in net income           $ 565,092   
Net income per common unit (basic and diluted)           $ 3.83   
Weighted average number of common units outstanding             147,600,000   

The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

 

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CVR Refining LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Nine Months Ended September 30, 2011

(dollars in thousands)

 

     Historical     (c)
Pro Forma  Adjustments
to Give Effect to
the Gary Williams
Acquisition
    Pro Forma
Adjustments to
Give Effect to
the Refinancing of
Notes
    Pro Forma  
        

Net sales

   $ 3,773,336      $ 2,041,264      $ —        $ 5,814,600   

Operating costs and expenses:

        

Cost of product sold (exclusive of depreciation and amortization)

     3,078,543        1,699,794        —          4,778,337   

Direct operating expenses (exclusive of depreciation and amortization)

     143,974        74,566        —          218,540   
        
        

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     31,487        13,093        —          44,580   
        

Depreciation and amortization

     50,872        21,752        —          72,624   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     3,034,876        1,809,205        —          5,114,081   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     468,460        232,059        —          700,519   

Other income (expense):

        

Interest expense and other financing costs

     (39,198     (4,160     10,576     (31,383
         1,399  

Realized loss on derivatives, net

     (18,298     (22,897     —          (41,195

Unrealized loss on derivatives, net

     (6,801     (37,854     —          (44,655

Loss on extinguishment of debt

     (2,078     —          —          (2,078

Other income, net

     737        (33     —          704   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (65,638     (64,944     11,975        (118,607
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 402,822      $ 167,115      $ 11,975      $ 581,912   
  

 

 

   

 

 

   

 

 

   

 

 

 

Common unitholders’ interest in net income

         $ 581,912   

Net income per common unit (basic and diluted)

         $ 3.94   

Weighted average number of common units outstanding

           147,600,000   

The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

 

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Index to Financial Statements

CVR Refining LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2011

(dollars in thousands)

 

     Historical     (c)
Pro Forma  Adjustments
to Give Effect to
the Gary Williams
Acquisition
    Pro Forma
Adjustments to
Give Effect to
the Refinancing of
Notes
    Pro Forma  
        

Net sales

   $ 4,752,814      $ 2,645,531      $ —        $ 7,398,345   

Operating costs and expenses:

        

Cost of product sold (exclusive of depreciation and amortization)

     3,927,620        2,198,404        —          6,126,024   

Direct operating expenses (exclusive of depreciation and amortization)

     247,665        97,388        —          345,053   
        
        

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     50,982        21,684        —          72,666   
        

Depreciation and amortization

     69,852        29,002        —          98,854   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     4,296,119        2,346,478        —          6,642,597   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     456,695        299,053        —          755,748   

Other income (expense):

        

Interest expense and other financing costs

     (52,995     (5,300     14,816     (41,686
         1,793  

Realized loss on derivatives, net

     (7,182     (41,822     —          (49,004

Unrealized loss on derivatives, net

     85,262        98        —          85,360   

Loss on extinguishment of debt

     (2,078     —          —          (2,078

Other income, net

     578        122        —          700   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     23,585        (46,902     16,609        (6,708
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 480,280      $ 252,151      $ 16,609      $ 749,040   
  

 

 

   

 

 

   

 

 

   

 

 

 

Common unitholders’ interest in net income

         $ 749,040   

Net income per common unit (basic and diluted)

         $ 5.07   

Weighted average number of common units outstanding

           147,600,000   

The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012 AND FOR THE YEAR

ENDED DECEMBER 31, 2011

(dollars in thousands)

(1) Organization and Basis of Presentation

The unaudited pro forma condensed combined financial statements of CVR Refining, LP (the “Partnership”) have been derived from the audited and unaudited historical combined financial statements of CVR Refining, LP. The historical combined financial statements are comprised of the financial statements relating to the operating subsidiaries of Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, Inc., that will be transferred to the Partnership prior to the closing of this offering.

The unaudited pro forma condensed combined financial statements are not necessarily indicative of the results that the Partnership would have achieved had the transactions described herein actually taken place at the dates indicated, and do not purport to be indicative of future financial position or operating results. The unaudited pro forma condensed combined financial statements should be read in conjunction with the historical combined financial statements of the Partnership, the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.

The pro forma adjustments have been prepared as if the transactions described below had taken place on September 30, 2012, in the case of the pro forma combined balance sheet, or as of January 1, 2011, in the case of the pro forma combined statement of operations for December 31, 2011, September 30, 2012 and September 30, 2011.

The unaudited pro forma condensed combined financial statements reflect the following transactions:

 

   

The Partnership’s acquisition of Gary-Williams Energy Corporation at December 15, 2011 and the inclusion of the January 1, 2011 through December 15, 2011 pro forma financial results.

 

   

The issuance of $500.0 million of senior notes and the use of proceeds to repurchase the 9.0% senior secured notes due 2015.

 

   

The Partnership’s offer and sale of common units to the public in this offering and payment of related commissions and expenses.

 

   

The Partnership’s repayment of its second lien notes with proceeds from the initial public offering and related accrued interest.

 

   

The contribution by CRLLC of cash in an amount sufficient to maintain a cash balance on the IPO date of $340.0 million less any amount paid through the closing of this offering to fund the turnaround of the Partnership’s Wynnewood refinery in the fourth quarter of 2012.

 

   

The Partnership’s issuance of an additional 3,000,000 common units to CVR Refining Holdings upon the expiration of the underwriter’s option to purchase additional common units without exercise.

Following completion of the Partnership’s initial public offering, the Partnership anticipates incurring incremental general and administrative expenses as a result of being 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. The Partnership estimates that these incremental general and administrative expenses will approximate $5.0 million per year. The Partnership’s unaudited pro forma condensed combined financial statements do not reflect this $5.0 million in incremental expenses.

(2) Pro Forma Balance Sheet Adjustments and Assumptions

 

  a) Reflects the issuance of $500.0 million principal amount of new notes by CVR Refining, LLC recorded at face amount.

 

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Index to Financial Statements

CVR Refining LP

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS —(Continued)

 

 

  b) Reflects the estimated deferred financing costs, including professional fees incurred, of $9.0 million associated with the new notes which includes $0.9 million of current and $8.1 million of long-term deferred costs.

 

  c) Reflects the repayment of indebtedness outstanding under the first lien notes of $447.1 million. $323.0 million of first lien notes are tendered at 107.2% and $124.1 million are redeemed at 106.75%. Reflects the payment of $20.1 million accrued interest at the repayment date of the notes. Reflects the write-off of previously deferred financing fees associated with the first lien notes including the current amount of $3.3 million and the long-term amount of $5.1 million.

 

  d) Reflects the recognition of the remaining unamortized premium on the first lien notes.

 

  e) Reflects the contribution by CRLLC prior to the initial public offering that would have been necessary to maintain a cash balance on the IPO of $340.0 million, based upon the historical cash and cash equivalents on hand as of September 30, 2012.

 

  f) Reflects the issuance by CVR Refining, LP of 20,000,000 common units to the public at an initial public offering price of $25.00 per common unit resulting in aggregate proceeds of $500.0 million.

 

  g) Reflects the payment of underwriting discounts and commissions and structuring fees and other estimated offering expenses of $31.0 million which will be allocated to the newly issued public common units.

 

  h) Reflects the repayment of indebtedness outstanding under the second lien notes of $222.8 million with initial public offering proceeds. Second lien notes are redeemed through a combination of clawback and make-whole which approximates a repayment at 111.35%. Reflects the payment of $12.1 million accrued interest at the repayment date of the notes. Reflects the write-off of previously deferred financing fees associated with the second lien notes which includes $0.9 million of unamortized current deferred and $3.1 million of long-term.

 

  i) Reflects the write-off of original issue discount on the second lien notes.

 

  j) Reflects the elimination of divisional equity converted into limited partner interests.

 

  k) Reflects the non-economic general partner interest with nominal value.

(3) Pro Forma Statement of Operations Adjustments and Assumptions

 

  a) Reflects the elimination of the interest associated with the repaid first and second lien notes and the inclusion of interest expense relating to the new notes at an assumed rate of 6.5% reflected below.

 

    Nine Months Ended
September 30, 2012
    Nine Months  Ended
September 30, 2011
    Twelve Months Ended
December 31, 2011
 
    (in thousands)  

Elimination of historical interest expense on first lien notes

  $ (30,226   $ (16,691   $ (23,000

Elimination of historical interest expense on second lien notes

    (18,168     (18,260     (24,316

Estimated interest on new notes

    24,375        24,375        32,500   
 

 

 

   

 

 

   

 

 

 

Total reduction to interest expense

  $ (24,019   $ (10,576   $ (14,816
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

CVR Refining LP

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS

 

 

  b) Reflects the amortization of related debt issuance costs of the new credit facility over an eight year term with reduction for amortization of deferred financing fees associated with the repaid first lien and second lien notes as reflected below.

 

     Nine Months Ended
September 30, 2012
    Nine Months Ended
September 30, 2011
    Twelve Months Ended
December 31, 2011
 
     (in thousands)  

Elimination of amortization of historical deferred financing fees on first and second lien notes

   $ (3,184   $ (1,692   $ (2,329

Elimination of recognition of amortization of original issuance premium, net on first and second lien notes

     2,163        (382     (364

Amortization of new notes issuance costs

     675        675        900   
  

 

 

   

 

 

   

 

 

 

Total decrease in amortization of financing fees

   $ (346   $ (1,399   $ (1,793
  

 

 

   

 

 

   

 

 

 

 

  c) Reflects the inclusion of pro forma adjustments related to the acquisition of Gary-Williams Energy Corporation (“WEC”) which occurred on December 15, 2011. The unaudited Pro forma adjustments include the financial results of WEC for the period from January 1, 2011 through the acquisition date of December 15, 2011 and give pro forma effect of the acquisition of WEC as if WEC had been acquired on January 1, 2011. The WEC acquisition was accounted for under the purchase method of accounting. The following pro forma adjustments are reflected for the acquisition.

 

   

Depreciation and amortization of the historical financial statements of WEC for the nine months ended September 30, 2011 and the twelve months ended December 31, 2011 was increased by $8.7 million and $13.2 million, respectively, to reflect the estimated additional depreciation related to the increase in property, plant and equipment based on the fair market value of the acquired assets.

 

   

Interest expense for the nine months ended September 30, 2011 and the twelve months ended December 31, 2011 has been reduced by $18.7 million and $29.0 million, respectively, for the historical WEC interest expense associated with historical debt that was repaid by WEC prior to the closing of the acquisition.

 

   

WEC’s turnaround expenses recorded prior to the acquisition of $9.8 million and $11.6 million for the nine months ended September 30, 2011 and the twelve months ended December 31, 2011, respectively, have been eliminated to conform to the Partnership’s accounting method.

(4) Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the provisions of the Partnership’s partnership agreement, to the common unitholders, by the number of common units expected to be outstanding at the closing of this offering. For purposes of this calculation, the Partnership assumed that pro forma distributions were equal to pro forma net income and that the number of units outstanding was 147,600,000 common units. All units were assumed to have been outstanding since January 1, 2012 for the September 30, 2012 pro forma financials and January 1, 2011 for the September 30, 2011 and December 31, 2011 pro forma financials.

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.

 

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Report of Independent Registered Public Accounting Firm

The General Partner of CVR Refining, LP

We have audited the accompanying balance sheet of CVR Refining, LP (the Partnership) as of September 17, 2012. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of CVR Refining, LP as of September 17, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

September 28, 2012

 

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Index to Financial Statements

CVR Refining, LP

BALANCE SHEET

(dollars in thousands)

 

     As of
September 17,
2012
 
     (in thousands)  

Assets:

  

Total Assets

   $ —     
  

 

 

 

Liabilities:

  

Total Liabilities

   $ —     
  

 

 

 

Partners’ Equity:

  

Limited Partner’s Equity

   $ 1   

Receivables from Partner

     (1
  

 

 

 

Total Partners’ Equity

   $ —     
  

 

 

 

See accompanying notes to this financial statement.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO THE FINANCIAL STATEMENT

1. Nature of Operations

CVR Refining, LP (the “Partnership”) is a Delaware limited partnership formed on September 17, 2012 by CVR Refining Holdings, LLC and CVR Refining GP, LLC. The Partnership was formed to own and operate the Coffeyville and Wynnewood refineries and the supporting logistic assets including approximately 350 miles of mainline pipelines, over 125 crude oil transports, a network of strategically located crude oil gathering tanks, and over 6.0 million barrels of leased and owned crude oil storage capacity.

CVR Refining Holdings, LLC was formed on September 17, 2012 by Coffeyville Resources, LLC, a controlled subsidiary of CVR Energy, Inc. CVR Refining Holdings, LLC has committed to contribute $1,000 to the Partnership in exchange for a 100% limited partner interest in the Partnership. This contribution receivable is reflected as a reduction to equity in accordance with generally accepted accounting principles. The accompanying financial statement reflects the financial position of the Partnership immediately subsequent to this initial capitalization. There have been no other transactions involving the Partnership as of September 28, 2012. CVR Refining GP, LLC, the general partner of the Partnership, owns a non-economic general partner interest in the Partnership.

2. Subsequent Events

Management of the Partnership evaluated subsequent events through the date of issuance of the balance sheet.

 

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Index to Financial Statements

CVR Refining, LP

CONDENSED COMBINED BALANCE SHEETS

 

     September  30,
2012
     December  31,
2011
 
     (unaudited)         
     (in thousands)  

ASSETS

     

Current assets:

     

Cash and cash equivalents

   $ 79,550       $ 2,745   

Accounts receivable, net of allowance for doubtful accounts of $1,766 and $1,206, respectively, including $938 and $986 from affiliates at September 30, 2012 and December 31, 2011, respectively

     273,746         174,831   

Inventories

     494,744         613,330   

Prepaid expenses and other current assets, including $916 and $881 due from affiliates at September 30, 2012 and December 31, 2011, respectively

     24,698         104,096   

Insurance receivable

     1,233         1,939   
  

 

 

    

 

 

 

Total current assets

     873,971         896,941   

Property, plant, and equipment, net

     1,319,768         1,320,787   

Deferred financing costs, net

     13,045         17,154   

Insurance receivable

     4,076         4,076   

Other long-term assets, including $473 and $850 due from affiliates at September 30, 2012 and December 31, 2011, respectively

     1,805         23,461   
  

 

 

    

 

 

 

Total assets

   $ 2,212,665       $ 2,262,419   
  

 

 

    

 

 

 

LIABILITIES AND DIVISIONAL EQUITY

     

Current liabilities:

     

Capital lease obligations

     $1,054       $ 960   

Accounts payable, including $152 and $278 due to affiliates at September 30, 2012 and December 31, 2011, respectively

     354,029         446,840   

Personnel accruals

     13,243         9,456   

Accrued taxes other than income taxes

     21,312         28,043   

Accrued expenses and other current liabilities, including $179 to affiliates at September 30, 2012 and December 31, 2011

     147,972         26,900   
  

 

 

    

 

 

 

Total current liabilities

     537,610         512,199   

Long-term liabilities:

     

Long-term debt and capital lease obligations, net of current portion

     725,937         728,903   

Accrued environmental liabilities, net of current portion

     1,331         1,459   

Other long-term liabilities, including $1,360 and $1,495 due to affiliates at September 30, 2012 and December 31, 2011, respectively

     10,093         1,232   
  

 

 

    

 

 

 

Total long-term liabilities

     737,361         731,594   

Commitments and contingencies (Note 11)

     

Divisional equity

     937,694         1,018,626   
  

 

 

    

 

 

 

Total liabilities and divisional equity

   $ 2,212,665       $ 2,262,419   
  

 

 

    

 

 

 

See accompanying notes to condensed combined financial statements.

 

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CVR Refining, LP

CONDENSED COMBINED STATEMENTS OF OPERATIONS

 

     Nine Months Ended
September 30,
 
     2012     2011  
    

(unaudited)

(in thousands)

 

Net sales

   $ 6,465,571      $ 3,773,336   

Operating costs and expenses:

    

Cost of product sold (exclusive of depreciation and amortization)

     5,191,032        3,078,543   

Direct operating expenses (exclusive of depreciation and amortization)

     253,176        143,974   

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     67,554        31,487   

Depreciation and amortization

     80,355        50,872   
  

 

 

   

 

 

 

Total operating costs and expenses

     5,592,117        3,304,876   
  

 

 

   

 

 

 

Operating income

     873,454        468,460   

Other income (expense):

    

Interest expense and other financing costs

     (56,044     (39,198

Realized loss on derivatives, net

     (80,426     (18,298

Unrealized loss on derivatives, net

     (196,980     (6,801

Loss on extinguishment of debt

     —          (2,078

Other income, net

     723        737   
  

 

 

   

 

 

 

Total other income (expense)

     (332,727     (65,638
  

 

 

   

 

 

 

Net income

   $ 540,727      $ 402,822   
  

 

 

   

 

 

 

See accompanying notes to condensed combined financial statements.

 

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CVR Refining, LP

CONDENSED COMBINED STATEMENT OF CHANGES IN DIVISIONAL EQUITY

 

     Divisional Equity  
     (unaudited)  
     (in thousands)  

Balance at December 31, 2011

   $ 1,018,626   

Share-based compensation—Affiliates

     15,563   

Net income

     540,727   

Distributions to parent, net

     (637,222
  

 

 

 

Balance at September 30, 2012

   $ 937,694   
  

 

 

 

See accompanying notes to condensed combined financial statements.

 

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CVR Refining, LP

CONDENSED COMBINED STATEMENTS OF CASH FLOWS

 

    Nine Months Ended
September 30,
 
    2012     2011  
    (unaudited)  
    (in thousands)  

Cash flows from operating activities:

   

Net income

  $ 540,727      $ 402,822   

Adjustments to reconcile net income to net cash provided by operating activities:

   

Depreciation and amortization

    80,355        50,872   

Allowance for doubtful accounts

    560        169   

Amortization of deferred financing costs

    5,139        2,818   

Amortization of original issue discount

    410        382   

Amortization of original issue premium

    (2,573     —     

Loss on disposition of fixed assets

    1,013        1,570   

Loss on extinguishment of debt

    —          2,078   

Share-based compensation—Affiliates

    15,563        7,963   

Unrealized (gain) loss on derivatives, net

    196,980        6,801   

Change in assets and liabilities:

   

Accounts receivable

    (99,475     (1,597

Inventories

    118,586        (56,944

Prepaid expenses and other current assets

    17,996        (21,124

Insurance receivable

    216        (6,445

Insurance proceeds for Refinery incident

    490        4,000   

Other long-term assets

    2,618        (1,512

Accounts payable

    (90,545     15,528   

Accrued expenses and other current liabilities

    11,100        17,068   

Accrued environmental liabilities

    (128     (962

Other long-term liabilities

    128        1,406   
 

 

 

   

 

 

 

Net cash provided by operating activities

    799,160        424,893   
 

 

 

   

 

 

 

Cash flows from investing activities:

   

Capital expenditures

    (82,813     (33,584

Proceeds from sale of assets

    405        47   
 

 

 

   

 

 

 

Net cash used in investing activities

    (82,408     (33,537
 

 

 

   

 

 

 

Cash flows from financing activities:

   

Principal payments on long-term debt

    (149     —     

Payment of capital lease obligations

    (560     —     

Principal payments on senior secured notes

    —          (2,700

Payment of deferred financing costs

    (2,016     (5,870

Distributions to parent, net

    (637,222     (385,113
 

 

 

   

 

 

 

Net cash used in financing activities

    (639,947     (393,683
 

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

    76,805        (2,327

Cash and cash equivalents, beginning of period

    2,745        2,327   
 

 

 

   

 

 

 

Cash and cash equivalents, end of period

  $ 79,550      $ —     
 

 

 

   

 

 

 

Supplemental disclosures:

   

Cash paid for interest, net of capitalized interest of $3,036 and $638 in 2012 and 2011, respectively

  $ 36,482      $ 24,260   

Non-cash investing and financing activities:

   

Accrual of construction in progress additions

  $ (2,266   $ 17,697   

See accompanying notes to condensed combined financial statements.

 

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CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

September 30, 2012

(unaudited)

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

The accompanying condensed combined financial statements of CVR Refining, LP (referred to as “CVR Refining” or the “Partnership”) have been prepared in connection with the proposed initial public offering (the “Offering”) of its common units representing limited partner interests. CVR Refining is a Delaware limited partnership, formed in September 2012 by CVR Energy, Inc. (“CVR Energy”). In October 2012, Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, contributed all of its interest in the operating subsidiaries which constituted its petroleum refining and related logistics business, as well as Coffeyville Finance Inc., to a newly-formed subsidiary, CVR Refining, LLC. The operating subsidiaries contributed to CVR Refining, LLC include the following entities: Wynnewood Energy Company, LLC (“WEC”); Wynnewood Refining Company, LLC (“WRC”); Coffeyville Resources Refining & Marketing, LLC (“CRRM”); Coffeyville Resources Crude Transportation, LLC (“CRCT”); Coffeyville Resources Terminal, LLC (“CRT”); and Coffeyville Resources Pipeline, LLC (“CRP”). The entities contributed by CRLLC to CVR Refining in connection with the Offering are referred to herein as the “Refining Subsidiaries.” Prior to the closing of the Offering, CVR Refining Holdings, LLC, a wholly-owned subsidiary of CRLLC, will contribute its 100% membership interest in CVR Refining, LLC to the Partnership in exchange for the issuance of a designated number of common units of the Partnership to CVR Refining Holdings, LLC. CRLLC will retain its other assets, including common units representing an approximate 70% limited partner interest in CVR Partners, LP (“CVR Partners”), a New York Stock Exchange traded manufacturer of nitrogen fertilizer, and a 100% membership interest in CVR GP, LLC, the general partner of CVR Partners.

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

The Partnership’s general partner, CVR Refining GP, LLC, will manage the Partnership’s activities subject to the terms and conditions specified in the Partnership’s partnership agreement. The Partnership’s general partner will be owned by CVR Refining Holdings, LLC. The operations of the general partner, in its capacity as general partner will be managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CVR Refining Holdings, LLC as the sole member of the Partnership’s general partner and not by the board of directors of the general partner. The Partnership’s general partner will not be elected by the Partnership’s unitholders and will not be subject to re-election on a regular basis in the future. The officers of the general partner will manage the day-to-day affairs of the business.

On the closing date of the Offering, the Partnership will enter into a services agreement, pursuant to which the Partnership and its general partner will obtain certain management and other services from CVR Energy, and will enter into an existing omnibus agreement. Pursuant to the omnibus agreement, which was originally entered into by CVR Partners, CVR Energy and certain other parties in October 2007, the Partnership will agree not to, and will cause its controlled affiliates not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of CVR Partners’ outstanding units.

 

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CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

Icahn Acquisition

On April 18, 2012, IEP Energy LLC (“IEP Energy”), a majority owned subsidiary of Icahn Enterprises, L.P. (“Icahn Enterprises”), and certain other affiliates of Icahn Enterprises and Carl C. Icahn (collectively, the “IEP Parties”), entered into a Transaction Agreement (the “Transaction Agreement”) with CVR Energy, with respect to IEP Energy’s tender offer (the “Offer”) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent payment right for each share of CVR Energy common stock (the “CCP”), which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or prior to August 18, 2013 and such transaction closes. On May 7, 2012, the IEP Parties announced that a majority of the common stock of CVR Energy had been acquired through the Offer. As a result of the shares tendered into the Offer during the initial offering period, the subsequent offering period and subsequent additional purchases, the IEP parties owned approximately 82% of CVR Energy’s common stock as of September 30, 2012.

Pursuant to the Transaction Agreement, all employee restricted stock awards (“awards”) that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, additional share-based compensation was incurred at CVR Energy to revalue the unvested shares to the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

(2) Basis of Presentation and Principles of Consolidation

The accompanying financial statements have been prepared in accordance with Regulation S-X, Article 3, “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B, “Allocations of Expenses and Related disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by CVR Energy are only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. As a result, certain assumptions and estimates are made in order to allocate a reasonable share of such expenses to CVR Refining, so that the accompanying financial statements reflect substantially all costs of doing business. The allocations and related estimates and assumptions are described more fully in Note 14 (“Allocation of Costs”) and Note 15 (“Related Party Transactions”). CRLLC used a centralized approach to cash management and the financing of its operations. As a result, amounts owed to or from CRLLC are reflected as a component of divisional equity on the accompanying condensed combined Statements of Changes in Divisional Equity.

Accounts and balances related to the refining and related logistic operations were based on a combination of specific identification and allocations. CVR Energy and CRLLC have allocated various corporate overhead expenses based on a percentage of total refining and related logistics payroll to the total payrolls of its segments (i.e., the petroleum and fertilizer segments are comprised of CVR Refining and CVR Partners, respectively). These allocations are not necessarily indicative of the cost that the Partnership would have incurred had it operated as an independent stand-alone entity for all years presented.

(3) Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. The Partnership adopted this standard effective as of January 1, 2012. The adoption of this standard did not impact the condensed combined financial statement footnote disclosures.

In December 2011, the FASB issued ASU No. 2011-11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), which requires new disclosure standards to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under IFRS. ASU 2011-11 will be effective for annual periods beginning January 1, 2013 and interim periods within those annual periods. The Partnership believes this standard will expand its condensed combined financial statement footnote disclosures.

(4) Wynnewood Acquisition

On December 15, 2011, CVR Refining, through CRLLC, completed the acquisition of all the issued and outstanding shares of the Gary-Williams Energy Corporation (subsequently converted to WEC), including its two wholly-owned subsidiaries (the “Wynnewood Acquisition”), from The Gary-Williams Company, Inc. (the “Seller”). The total purchase price was $593.4 million. CVR Refining received settlement in the second quarter of 2012 of approximately $14.7 million associated with cash paid at closing for estimated working capital in excess of actual working capital. For the nine months ended September 30, 2012, CVR Refining incurred approximately $10.3 million of transaction fees and integration expenses that are included in selling, general and administrative expense in the condensed combined Statements of Operations.

(5) Share-Based Compensation

Certain employees of CVR Refining, and employees of CVR Energy and CRLLC who perform services for CVR Refining, participate in the equity compensation plans of CVR Refining’s affiliates. Accordingly, CVR Refining has recorded compensation expense for these plans in accordance with SAB Topic 1-B and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Refining has been allocated 100% to CVR Refining. For employees of CVR Energy and CRLLC performing services for CVR Refining, CVR Refining recorded share-based compensation relative to the percentage of time spent by each employee providing services to CVR Refining as compared to the total calculated share-based compensation by CVR Energy and CRLLC. CVR Refining is not responsible for payment of share-based compensation and all expense amounts are reflected as an increase or decrease to divisional equity.

Prior to CVR Energy’s initial public offering, CVR Energy’s subsidiaries were held and operated by Coffeyville Acquisition LLC (“CALLC”). CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR Energy’s initial public offering in October 2007, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”). In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. In addition, in connection with the transfer of the managing general partner of CVR Partners to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR Energy’s common stock, pursuant to a registered public offering. In May 2011, CALLC sold into the public market 7,988,179 shares of CVR Energy’s common stock, pursuant to a registered public offering.

As a result, CALLC and CALLC II are no longer stockholders of CVR Energy. Subsequent to CALLC’s and CALLC II’s divestiture of ownership interest in CVR Energy, no additional share-based compensation expense was incurred with respect to override units and phantom units after each respective divestiture date. The final fair values of the override units of CALLC and CALLC II were derived based upon the values resulting from the proceeds received associated with each entity’s respective divestiture of its ownership in CVR Energy. These values were utilized to determine the related compensation expense for the unvested units.

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III.

 

Award Type

   Benchmark
Value

(per Unit)
     Original
Awards
Issued
    

Grant Date

   Compensation Expense
Increase (Decrease) for the

Nine Months Ended
September 30, 2011
 
                        (in thousands)  

Override Value Units

   $ 11.31         1,839,265       June 2005      1,353   

Override Value Units

   $ 34.72         144,966       December 2006      (4

Override Units

   $ 10.00         642,219       February 2008      45   
           

 

 

 
         Total    $ 1,394   
           

 

 

 

Phantom Unit Plans

CVR Energy, through CRLLC, had two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees and service providers were awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points had rights to receive distributions when holders of override operating units received distributions. Holders of performance phantom points had rights to receive distributions when CALLC and CALLC II holders of override value units received distributions.

Compensation expense allocated for the nine months ended September 30, 2012 and 2011 related to the Phantom Unit Plans was $0 and approximately $4.2 million, respectively.

Long-Term Incentive Plan – CVR Energy

CVR Energy has a Long-Term Incentive Plan (“CVR Energy LTIP”) that permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock). As of September 30, 2012, only restricted shares of CVR Energy common stock and stock options had been granted under the CVR Energy LTIP. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy’s or its subsidiaries’ (including CVR Refining) employees, officers, consultants and directors.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

Restricted Stock and Restricted Stock Units

Through the CVR Energy LTIP, shares of restricted common stock and restricted stock units have been granted to employees of CVR Energy and CVR Refining. Prior to the change in control as discussed in Note 1, the restricted shares, when granted, were valued at the closing market price of CVR Energy’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the common stock. These shares generally vest over a three-year period. Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at September 30, 2012, there was approximately $7.5 million of total unrecognized compensation cost related to restricted shares to be recognized over a weighted-average period of approximately two years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that occur from time to time. The unrecognized compensation expense has been determined by the number of restricted shares and respective allocation percentage for individuals for whom, as of September 30, 2012, compensation expense has been allocated to CVR Refining.

Compensation expense recorded for the nine months ended September 30, 2012 and 2011, related to the restricted shares, was approximately $15.6 million and $2.4 million, respectively.

(6) Inventories

Inventories consisted of the following:

 

     September  30,
2012
     December  31,
2011
 
     (in thousands)  

Finished goods

   $ 256,158       $ 316,654   

Raw materials and precious metals

     173,341         154,530   

In-process inventories

     36,400         115,090   

Parts and supplies

     28,845         27,056   
  

 

 

    

 

 

 
   $ 494,744       $ 613,330   
  

 

 

    

 

 

 

(7) Property, Plant, and Equipment

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

 

     September  30,
2012
     December  31,
2011
 
     (in thousands)  

Land and improvements

   $ 21,490       $ 19,193   

Buildings

     34,887         33,887   

Machinery and equipment

     1,618,551         1,570,191   

Automotive equipment

     11,799         9,603   

Furniture and fixtures

     5,996         5,713   

Leasehold improvements

     768         413   

Construction in progress

     61,800         39,781   
  

 

 

    

 

 

 
   $ 1,755,291       $ 1,678,781   

Accumulated depreciation

     435,523         357,994   
  

 

 

    

 

 

 

Total net, property, plant and equipment

   $ 1,319,768       $ 1,320,787   
  

 

 

    

 

 

 

 

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CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

Capitalized interest recognized as a reduction in interest expense for the nine months ended September 30, 2012 and 2011 totaled approximately $3.0 million and $0.6 million, respectively. Land, building and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million as of September 30, 2012. Amortization of assets held under capital leases is included in depreciation expense.

(8) Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks and freight and distribution expense. For the nine months ended September 30, 2012 and 2011, there was $2.5 million and $1.8 million, respectively, in depreciation expense incurred related to the cost of product sold.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, and environmental compliance costs as well as chemical and catalyst and other direct operating expenses. Direct operating expenses also include allocated non-cash share-based compensation expense from CVR Energy and CALLC III, as discussed in Note 5 (“Share-Based Compensation”). For the nine months ended September 30, 2012 and 2011, direct operating expenses exclude depreciation and amortization of approximately $77.3 million and $48.9 million, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated legal, treasury, accounting, marketing, human resources and the cost of maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses also include allocated non-cash share-based compensation expense from CVR Energy and CALLC III, as discussed in Note 5 (“Share-Based Compensation”). Selling, general and administrative expenses exclude depreciation and amortization of $0.5 million and $0.1 million for the nine months ended September 30, 2012 and 2011, respectively.

(9) Insurance Claims

On December 28, 2010, the Coffeyville crude oil refinery experienced an equipment malfunction and a small fire in connection with its fluid catalytic cracking unit (“FCCU”), which led to reduced crude oil throughput. The refinery returned to full operation on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of December 31, 2011 were approximately $8.0 million. No costs have been recorded in 2012.

CVR Refining maintains property damage insurance policies through CRLLC which have an associated deductible of $2.5 million. CVR Refining anticipates that substantially all of the repair costs in excess of the deductible should be covered by insurance. As of December 31, 2011, approximately $4.0 million of insurance proceeds have been received under the property damage insurance related to this incident. An insurance receivable has been recorded related to the incident of approximately $1.2 million as of September 30, 2012. The insurance receivable is included in current assets in the condensed combined Balance Sheet.

The Coffeyville crude oil refinery experienced a small fire at its continuous catalytic reformer (“CCR”) in May 2011. Total gross repair and other costs related to the incident, as of September 30, 2012, were approximately $3.2 million. No costs have been recorded in 2012. Approximately $0.5 million of insurance proceeds were received during the nine months ended September 30, 2012.

As of September 30, 2012, CVR Refining has recorded an insurance receivable of approximately $0.2 million. During October 2012, the remaining insurance proceeds of $0.2 million were received and all claims associated with the fire at the CCR have been fully settled and closed. Substantially all costs incurred in excess of the associated $2.5 million deductible were recovered by insurance.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

(10) Long-Term Debt

As of September 30, 2012 and December 31, 2011 there was $33.6 million and $17.0 million, respectively, of accrued interest related to debt obligations in accrued expenses and other liabilities on the condensed combined Balance Sheets. Long-term debt was as follows:

 

     September 30,
2012
     December 31,
2011
 
     (in thousands)  

9.0% Senior Secured Notes, due 2015, net of unamortized premium of $6,604(1) and $9,003(2) as of September 30, 2012 and December 31, 2011, respectively

   $ 453,654       $ 456,053   

10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1,923 and $2,159 as of September 30, 2012 and December 31, 2011, respectively

     220,827         220,591   

Capital lease obligations

     51,456         52,259   
  

 

 

    

 

 

 

Long-term debt

   $ 725,937       $ 728,903   
  

 

 

    

 

 

 

 

(1) Net unamortized premium of $6.6 million represents an unamortized discount of $0.7 million on the original First Lien Notes and a $7.3 million unamortized premium on the additional First Lien Notes issued in December 2011.
(2) Net unamortized premium of $9.0 million represents an unamortized discount of $0.9 million on the original First Lien Notes and a $9.9 million unamortized premium on the additional First Lien Notes issued in December 2011.

Senior Secured Notes

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Notes is amortized to interest expense and other financing costs over the respective term of the Notes. On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of approximately $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million. On May 16, 2011, CRLLC repurchased $2.7 million of the Notes at a purchase price of 103.0% of the outstanding principal amount, which resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized issue discount. As the Notes were incurred for the benefit of the operations of CVR Refining, all the debt and associated costs have been allocated to CVR Refining.

On December 15, 2011, the Issuers issued an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “New Notes”). The New Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of the New Notes is amortized to interest expense and other financing costs over the respective term of the New Notes. The New Notes were issued as “Additional Notes” pursuant to an indenture dated April 6, 2010 (the “Indenture”) and, together with the existing first lien notes, are treated as a single class for all purposes under the Indenture including, without limitation, waivers, amendments, redemptions and other offers to purchase. Unless otherwise indicated, the New Notes and the existing first lien notes are collectively referred to herein as the “First Lien Notes.”

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

The change of control of CVR Energy required CRLLC to make an offer to repurchase all of the Issuers’ outstanding Notes; and on June 4, 2012, the Issuers offered to purchase all or any part of the Notes, at a cash purchase price of 101% of the aggregate principal amount of the Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Notes tendered.

The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See Note 16 (“Subsequent Events”) for further discussion related to the recent tender of a portion of the First Lien Notes. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year. At September 30, 2012, the estimated fair value of the First and Second Lien Notes was approximately $484.3 million and $247.3 million, respectively. These estimates of fair value are Level 2 as they were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC’s subsidiaries other than CVR Partners and CRNF.

ABL Credit Facility

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (the “ABL credit facility”) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility is scheduled to mature in August 2015 and replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility will be used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to additional lender commitments. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase the borrowings under the ABL credit facility to $400.0 million in the aggregate in connection with the New Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. As of September 30, 2012, CRLLC had availability under the ABL credit facility of $372.8 million and had letters of credit outstanding of approximately $27.2 million. There were no borrowings outstanding under the ABL credit facility as of September 30, 2012.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

The ABL credit facility contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, the incurrence of liens on assets, and the ability to dispose of assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. The ABL credit facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. As of September 30, 2012, CRLLC was in compliance with the covenants contained in the ABL credit facility.

In connection with the ABL credit facility, CRLLC incurred lender and other third-party costs of approximately $9.1 million for the year ended December 31, 2011. As the ABL credit facility was incurred for the benefit of the operations of CVR Refining, all the debt and associated costs have been allocated to CVR Refining. These costs were deferred and are being amortized to interest expense and other financing costs using a straight-line method over the term of the facility. In connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

$1.9 million, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.8 million of unamortized deferred financing costs associated with the first priority credit facility will continue to be amortized over the term of the ABL credit facility.

In connection with the closing of CVR Partners’ initial public offering in April 2011, CVR Partners and CRNF, a wholly-owned subsidiary of CVR Partners, were released as guarantors of the ABL credit facility.

In connection with the change in control of CVR Energy, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the “ABL First Amendment”), pursuant to which the parties agreed to exclude Icahn’s acquisition of the common shares of CVR Energy from the definition of change of control as provided in the ABL credit facility. Absent the ABL First Amendment, the change in control of CVR Energy would have triggered an event of default pursuant to the ABL credit facility.

(11) Commitments and Contingencies

The minimum required payments for the Partnership’s operating leases and unconditional purchase obligations are as follows:

 

     Operating
Leases
     Unconditional
Purchase
Obligations(1)
 
     (in thousands)  

Three months ending December 31, 2012

   $ 785       $ 29,200   

Year ending December 31, 2013

     2,785         114,666   

Year ending December 31, 2014

     2,237         107,424   

Year ending December 31, 2015

     1,408         96,854   

Year ending December 31, 2016

     956         90,218   

Thereafter

     442         439,216   
  

 

 

    

 

 

 
   $ 8,613       $ 877,578   
  

 

 

    

 

 

 

 

(1) This amount includes approximately $482.8 million payable ratably over nine years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM will receive transportation for at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

CVR Refining leases trucks, tractor trailers and facilities under long-term operating leases expiring at various dates. Lease expense for the nine months ended September 30, 2012 and 2011 totaled approximately $2.3 million and $1.1 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR Refining’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.

Crude Oil Supply Agreement

On August 31, 2012, CRRM and Vitol Inc. (“Vitol”), entered into an Amended and Restated Crude Oil Supply Agreement (the “Vitol Agreement”). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the “Previous Supply Agreement”).

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

The terms of the Vitol Agreement provide that CRRM will obtain all of the crude oil for the Company’s two oil refineries through Vitol, other than crude oil that CRRM acquires in Kansas, Missouri, North Dakota, Oklahoma, Texas, Wyoming and all states adjacent to such states and crude oil that is transported in whole or in part via railcar or truck. Pursuant to the Vitol Agreement, CRRM and Vitol work together to identify crude oil and pricing terms that meet CRRM’s crude oil requirements. CRRM and/or Vitol negotiate the cost of each barrel of crude oil that is purchased from third party crude oil suppliers. Vitol purchases all such crude oil, executes all third party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to CRRM. Title and risk of loss for all crude oil purchased by CRRM via the Vitol Agreement passes to CRRM upon delivery to one of the Company’s delivery points designated in the Vitol Agreement. CRRM pays Vitol a fixed origination fee per barrel plus the negotiated cost (including logistics costs) of each barrel of crude oil purchased. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the “Initial Term”). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a “Renewal Term”) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

Litigation

From time to time, CVR Refining is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Management believes the Partnership has accrued for losses for which it may ultimately be responsible. It is possible that management’s estimates of the outcomes will change due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any litigation matters is not expected to have a material adverse effect on the accompanying condensed combined financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, “Samson”) filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs filed two lawsuits (the “Anstine and Arrow cases”) against CRRM and other defendants in state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remained in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the SemGroup bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, “Sem”), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased from Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company (“J. Aron”) and that J. Aron sold some of this crude oil to CRRM. All of the lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of the plaintiffs’ alleged claims is unknown since the price and amount of crude oil sold by the plaintiffs and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, and J. Aron agreed to reimburse CRRM’s prior attorney fees and out-of-pocket expenses in connection with the lawsuits. Samson and CRRM entered a stipulation of dismissal with respect to all of the Samson cases and the Samson cases were dismissed with prejudice on February 8, 2012. The dismissal does not pertain to the Anstine and Arrow cases.

On July 25, 2011, Mid-America Pipeline Company, LLC (“MAPL”) filed an application with the Kansas Corporation Commission (“KCC”) for the purpose of establishing higher rates (“New Rates”) effective October 1, 2011 for pipeline transportation service on MAPL’s liquids pipelines running between Conway, Kansas and Coffeyville, Kansas (“Inbound Line”) and between Coffeyville, Kansas and El Dorado, Kansas (“Outbound Line”). CRRM ships refined fuels on the Outbound Line and CRRM ships natural gas liquids on the Inbound Line. On April 3, 2012, the parties entered into a Settlement Agreement which resolved the rate dispute both at the KCC and at the U.S. Federal Energy Regulatory Commission (“FERC”). Among other provisions, the Settlement Agreement provides for pipeage contracts to be entered into between the parties with rates (“Settlement Rates”) to be established for an initial one year period. The Settlement Rates consist of two components, a base rate and a pipeline integrity cost recovery rate along with an annual take or pay minimum transportation quantity. The Settlement Rate on the Inbound Line was effective April 1, 2012 and the Settlement Rate on the Outbound Line was effective June 1, 2012. Prior to the end of the initial one year term of the pipeage contracts, and prior to the end of each annual period thereafter until the tenth anniversary of each of the two pipeage contracts, MAPL will provide its estimate of pipeline integrity costs for the upcoming annual period and CRRM may either agree to pay a rate for such upcoming annual period which includes a recovery rate component sufficient to collect such pipeline integrity costs for such upcoming annual period subject to true-up to actual costs at the end of the annual period. FERC rates will be the same as the KCC rates.

Flood, Crude Oil Discharge and Insurance

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

As a result of the crude oil discharge that occurred on July 1, 2007, the Partnership entered into an administrative order on consent (the “Consent Order”) with the U.S. Environmental Protection Agency (the “EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from the Partnership’s Coffeyville refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Partnership agreed to perform specified remedial actions to respond to the discharge of crude oil from the Partnership’s refinery. The substantial majority of all required remedial actions were completed by January 31, 2009. The Partnership prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided the Partnership with a notice of completion indicating that the Partnership has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties.

 

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CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

On October 25, 2010, the Partnership received a letter from the United States Coast Guard on behalf of the EPA seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard’s claim for oversight costs. On September 23, 2011, the United States Department of Justice (“DOJ”), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking (i) recovery from CRRM of the EPA’s oversight costs under the OPA, (ii) a civil penalty under the Clean Water Act (as amended by the OPA) and (iii) recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (“RMP”). (See “Environmental, Health and Safety (“EHS”) Matters” below.) The Partnership has reached an agreement in principle with the DOJ to resolve the DOJ’s claims. The Partnership anticipates that civil penalties associated with the proceeding will exceed $100,000; however, the Partnership does not anticipate that civil penalties or any other costs associated with the proceeding will be material. The lawsuit is stayed while the consent decree is finalized.

CVR Refining is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, one of CVR Refining’s subsidiaries filed a lawsuit in the United States District Court for the District of Kansas against certain of its environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, the Partnership cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the claims. The Partnership has received $25 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment of the primary pollution liability policy limit.

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

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

CRRM, CRCT, CRT and WRC are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.

CRRM, CRCT, WRC and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution. Therefore, CRRM, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States.

 

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CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under the RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of September 30, 2012 and December 31, 2011, environmental accruals of approximately $1.6 million and $1.9 million, respectively, were reflected in the condensed combined Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.3 million and $0.5 million, respectively, are included in other current liabilities. The Partnership’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at September 30, 2012 and December 31, 2011, respectively. The accruals include estimated closure and post-closure costs of approximately $0.9 million and $0.9 million for two landfills at September 30, 2012 and December 31, 2011, respectively. The estimated future payments for these required obligations are as follows:

 

     Amount  
     (in thousands)  

Three months ending December 31, 2012

   $ 147   
Year Ending December 31,   

2013

     200   

2014

     162   

2015

     162   

2016

     105   

Thereafter

     1,055   
  

 

 

 

Undiscounted total

     1,831   

Less amounts representing interest at 1.59%

     193   
  

 

 

 

Accrued environmental liabilities at September 30, 2012

   $ 1,638   
  

 

 

 

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

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

In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. With the change in control by Icahn Enterprises in 2012, the MSAT II projects have been accelerated by three months due to the loss of small refiner status. Capital expenditures to comply with the rule are expected to be approximately $59 million for CRRM and $78 million for WRC.

 

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CRRM’s refinery is subject to the Renewable Fuel Standard (“RFS”) which requires refiners to blend “renewable fuels” in with their transportation fuels or purchase renewable energy credits in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2012, about 9% of all fuel used was required to be “renewable fuel.” The EPA has not yet proposed the renewable fuel percentage standards for 2013. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (“RINs”) in lieu of blending. To achieve compliance with the renewable fuel standard for the remainder of 2012, CRRM is able to blend a small amount of ethanol into gasoline sold at its refinery loading rack, but otherwise will have to purchase RINs to comply with the rule. CRRM requested “hardship relief” (an extension of the compliance deadline) from the EPA based on the disproportionate economic impact of the rule on CRRM, but the EPA denied CRRM’s request on February 17, 2012.

WRC’s refinery is a small refinery under the RFS and has received a two year extension of time to comply. Therefore, WRC will have to begin complying with the RFS beginning in 2013 unless a further extension is requested and granted.

The EPA is expected to propose “Tier 3” gasoline sulfur standards in 2012 or 2013. If the EPA were to propose a standard at the level recently being discussed in the pre-proposal phase by the EPA, CRRM will need to make modifications to its equipment in order to meet the anticipated new standard. It is not anticipated that the Wynnewood refinery would require additional capital to meet the anticipated new standard. The Partnership does not believe that costs associated with the EPA’s proposed Tier 3 rule will be material.

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

In March 2012, CRRM entered into a “Second Consent Decree” with the EPA, which replaces the 2004 Consent Decree (other than the RCRA provisions) and the First Material Modification. The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a “global settlement” under the EPA’s “National Petroleum Refining Initiative.” Under the National Petroleum Refining Initiative, the EPA identified industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Partnership was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, the remaining costs of which are expected to be approximately $49.0 million, of which approximately $47.0 million is expected to be capital expenditures and complete a voluntary environmental project that will

 

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reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012.

WRC’s refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the “ODEQ”) under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the “Wynnewood Consent Order”). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The costs of complying with the Wynnewood Consent Order, other than costs associated with a planned turnaround, are not expected to be material. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order. The EPA may later request that WRC enter into a global settlement which, if WRC agreed to do so, would necessitate the payment of a civil penalty and the installation of additional controls.

On February 24, 2010, CRRM received a letter from the DOJ on behalf of the EPA seeking an approximately $0.9 million civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”). The Partnership reached an agreement with EPA to resolve these claims. The resolution was included in the Second Consent Decree described above pursuant to which the Partnership has agreed to pay an immaterial civil penalty.

The EPA has investigated CRRM’s operation for compliance with the Clean Air Act’s RMP. On September 23, 2011, the DOJ, acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas (in addition to the matters described above, see “Flood, Crude Oil Discharge and Insurance”) seeking recovery from CRRM related to alleged non-compliance with the RMP. The Partnership has reached an agreement to settle the claims. Civil penalties associated with the proceeding will exceed $100,000; however, the Partnership does not anticipate that civil penalties or any other costs associated with the settlement will be material. The lawsuit is temporarily stayed while the parties attempt to finalize and file the consent decree.

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

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the nine months ended September 30, 2012 and 2011, capital expenditures were approximately $18.4 million and $3.4 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

 

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CRRM, CRCT, WRC and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.

Wynnewood Refinery Incident

On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit that had been temporarily shut down as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler; process units and other areas of the facility were unaffected. Additionally, there has been no evidence of environmental impact. The refinery was shut down for turnaround maintenance at the time of the incident. The Partnership immediately launched an internal investigation of the incident and continues to cooperate with U.S. Occupational Health and Safety Administration (“OSHA”) and Oklahoma Department of Labor (“ODL”) investigations.

(12) Fair Value of Financial Instruments

In September 2006, the FASB issued ASC Topic 820 – Fair Value Measurements and Disclosures (“ASC 820”). ASC 820 established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

 

   

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

 

   

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

 

   

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

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of September 30, 2012 and December 31, 2011.

 

     September 30, 2012  
     Level 1      Level 2     Level 3      Total  
     (in thousands)  
Location and Description   

Cash equivalents

   $ 5,715       $ —        $ —         $ 5,715   

Other current assets (other derivative agreements)

     —           —          —           —     

Other long-term assets (other derivative agreements)

     —           —          —           —     
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Assets

   $ 5,715       $ —        $ —         $ 5,715   
  

 

 

    

 

 

   

 

 

    

 

 

 

Other current liabilities (other derivative agreements)

     —           (107,028     —           (107,028

Other long-term liabilities (other derivative agreements)

     —           (8,733     —           (8,733
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Liabilities

   $ —         $ (115,761   $ —         $ (115,761
  

 

 

    

 

 

   

 

 

    

 

 

 

 

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     December 31, 2011  
     Level 1      Level 2      Level 3      Total  
     (in thousands)  
Location and Description            

Cash equivalents

   $ 2,745       $ —         $ —         $ 2,745   

Other current assets (other derivative agreements)

     —           63,051         —           63,051   

Other long-term assets (other derivative agreements)

     —           18,831         —           18,831   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets

   $ 2,745       $ 81,882       $ —         $ 84,627   
  

 

 

    

 

 

    

 

 

    

 

 

 

Other current liabilities (other derivative agreements)

     —           —           —           —     

Other long-term liabilities (other derivative agreements)

     —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Liabilities

   $ —         $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

As of September 30, 2012 and December 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining’s cash equivalents and derivative instruments. The fair value of the Notes is disclosed in Note 10 (“Long-Term Debt”). The commodity derivative contracts are valued using broker quoted market prices of similar commodity contracts using Level 2 inputs. CVR Refining had no transfers of assets or liabilities between any of the above levels during the nine months ended September 30, 2012.

(13) Derivative Financial Instruments

Loss on derivatives, net consisted of the following:

 

     Nine Months Ended
September 30,
 
     2012     2011  

Realized loss on other derivative agreements

   $ (80,426   $ (18,298

Unrealized loss on other derivative agreements

     (196,980     (6,801
  

 

 

   

 

 

 

Total loss on derivatives, net

   $ (277,406   $ (25,099
  

 

 

   

 

 

 

CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR Refining from time to time enters into various commodity derivative transactions. The Refining Subsidiaries, as further described below, entered into certain commodity derivate contracts and, through CRLLC, entered into an interest rate swap as required by the long-term debt agreements. The commodity derivative contracts are for the purpose of managing price risk on crude oil and finished goods.

CVR Refining has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR Refining holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the condensed combined Statements of Operations.

CVR Refining maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the condensed combined Balance Sheets. The maintenance margin balance is included within other current assets within the condensed combined Balance Sheets. Dependent upon the position of the open

 

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commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the condensed combined Balance Sheets. From time to time, CVR Refining may be required to deposit additional funds into this margin account. For the nine months ended September 30, 2012, CVR Refining recognized a realized loss of $10.1 million and an unrealized loss of $0.8 million which is recorded in loss on derivatives, net in the condensed combined Statements of Operations.

Commodity Swap

Beginning September 2011, subsidiaries of CRLLC, for the benefit of CRRM, entered into several commodity swap contracts with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the condensed combined Balance Sheets with changes in fair value currently recognized in the condensed combined Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At September 30, 2012, CVR Refining had open commodity hedging instruments consisting of 26.3 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at September 30, 2012 was a net loss of $115.6 million which was comprised of $106.9 million included in current liabilities and $8.7 million included in long-term liabilities. For the nine months ended September 30, 2012, CVR Refining recognized a realized loss of $70.3 million and an unrealized loss of $196.1 million which are recorded in loss on derivatives, net in the condensed combined Statements of Operations.

(14) Allocation of Costs

CVR Energy and CRLLC have allocated general and administrative expenses to CVR Refining based on allocation methodologies that management considers reasonable and result in an allocation of the cost of doing business borne by CVR Energy and CRLLC on behalf of CVR Refining; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

CVR Refining’s historical condensed combined Statements of Operations reflect all of the expenses that CRLLC and CVR Energy incurred on CVR Refining’s behalf. CVR Refining’s financial statements therefore include certain expenses incurred by its parent which may include, but are not necessarily limited to, the following:

 

   

Officer and employee salaries and share-based compensation;

 

   

Rent or depreciation;

 

   

Advertising;

 

   

Accounting, tax, legal and information technology services;

 

   

Other selling, general and administrative expenses;

 

   

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

 

   

Financing costs, including interest, mark-to-market changes in interest rate swap, and losses on extinguishment of debt.

Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining based upon percentages determined by management to be reasonable and in line with the nature of an individual’s roles and responsibilities. Allocations

 

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related to share-based compensation are more fully described in Note 5. Property insurance costs, included in direct operating expenses (exclusive of depreciation and amortization), were allocated based upon specific segment valuations. See Note 15 (“Related Party Transactions”) for a detailed discussion of transactions with affiliated entities. The table below reflects cost allocations, either allocated or billed, by period reflected in the condensed combined Statement of Operations.

 

     Nine Months Ended
September 30,
 
     2012       2011   
     (in thousands)  

Direct operating expenses (exclusive of depreciation and amortization)

   $ 8,808       $ 6,693   

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     48,910         20,189   
  

 

 

    

 

 

 
   $ 57,718       $ 26,882   
  

 

 

    

 

 

 

(15) Related Party Transactions

Related Party Agreements

In connection with the formation of CVR Refining in September 2012, CVR Refining and CRRM will enter into a services agreement with CVR Energy and its subsidiaries that governs the business relations among CVR Refining, its general partner and CRRM on the one hand, and CVR Energy and its subsidiaries, on the other hand. CRRM has previously entered into other agreements with CVR Partners and its subsidiary. Certain of the agreements described below were amended and restated on April 13, 2011 in connection with the initial public offering of CVR Partners. The agreements are described as in effect at September 30, 2012. Amounts owed to CRRM and WEC from CVR Energy and its subsidiaries with respect to these agreements are included in prepaid expenses and other current assets, and other long-term assets, on the condensed combined Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CRRM with respect to these agreements are included in accounts payable, accrued expenses and other current liabilities, and other long-term liabilities, on CVR Refining’s condensed combined Balance Sheets.

Feedstock and Shared Services Agreement

CRRM entered into a feedstock and shared services agreement with CRNF under which the two parties provide feedstock and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM’s Coffeyville, Kansas refinery and CRNF’s nitrogen fertilizer plant.

Pursuant to the feedstock agreement, CRRM and CRNF have the obligation to transfer excess hydrogen to one another. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining. Net monthly receipts of hydrogen from CRNF have been reflected in cost of product sold (exclusive of depreciation and amortization) for CVR Refining. For the nine months ended September 30, 2012 and 2011, the net sales generated from the sale of hydrogen to CRNF were approximately $0.2 million and $1.0 million, respectively. For the nine months ended September 30, 2012 and 2011, CVR Refining recognized $6.0 million and $11.8 million of cost of product sold (exclusive of depreciation and amortization) related to the receipt of excess hydrogen from the nitrogen fertilizer plant, respectively.

The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net reimbursed direct operating expenses recorded during the nine months ended September 30, 2012 and 2011 were approximately $42,000 and $0.2 million, respectively, related to high pressure steam. Reimbursed and paid amounts on a gross basis were nominal for the nine month periods.

CRNF is also obligated to make available to CRRM any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by CRNF in a commercially

 

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reasonable manner. Direct operating expenses incurred by CRRM associated with the purchase of nitrogen for the nine months ended September 30, 2012 and 2011, were approximately $1.3 million and $1.0 million, respectively. No amounts were paid by CRNF to CRRM for any of the years.

For the nine months ended September 30, 2012 and 2011, CRRM recognized approximately $0.2 million and $0.1 million, respectively, of direct operating expenses from the purchase of tail gas from CRNF.

In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF has agreed to pay CRRM the cost of installing the pipe over the next three years and to provide an additional 15% to cover the cost of capital in the fourth year. At September 30, 2012, there was an asset of approximately $0.5 million included in other current assets, approximately $0.5 million included in other non-current assets, an offset liability of approximately $0.2 million in other current liabilities and approximately $1.4 million of other non-current liabilities in the condensed combined Balance Sheet.

CRNF also provided finished product tank capacity to CRRM under the agreement. CRRM incurred approximately $0.1 million and $0.2 million for the use of tank capacity for the nine months ended September 30, 2012 and 2011, respectively. This cost was recorded as direct operating expenses.

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

At September 30, 2012 and December 31, 2011, payables of $0.2 million and $0.3 million, respectively, were included in accounts payable on the condensed combined Balance Sheets associated with amounts yet to be paid related to components of the feedstock and shared services agreement. At September 30, 2012 and December 31, 2011, receivables of $0.4 million and $0.3 million, respectively, were included in prepaids and other current assets on the condensed combined Balance Sheets associated with the amounts due from CRNF under the Feedstock and Shared Services Agreement.

Coke Supply Agreement

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

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

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

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

For the nine months ended September 30, 2012 and 2011, net sales of pet coke associated with the transfer of pet coke from CRRM to CRNF was approximately $7.3 million and $8.8 million, respectively. Receivables of $0.9 million and $1.0 million related to the coke supply agreement were included in prepaid expenses and other current assets on the condensed combined Balance Sheets at September 30, 2012 and December 31, 2011, respectively.

Lease Agreement

CRRM entered into a lease agreement with CRNF under which CRNF leases certain office and laboratory space. The initial term of the lease will expire in October 2017, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, CRNF has the option to renew the lease agreement for up to five additional one-year periods by providing CRRM with notice of renewal at least 60 days prior to the expiration of the then existing term. For the nine months ended September 30, 2012 and 2011, amounts received related to the use of the office and laboratory space were approximately $0.1 million and $0.1 million, respectively.

Environmental Agreement

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

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

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

Icahn Sourcing

Icahn Sourcing, LLC (“Icahn Sourcing”) is an entity formed and controlled by Carl C. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property. CVR Refining is a member of the buying group and, as such, is afforded the opportunity to purchase goods, services and property from vendors with whom Icahn Sourcing has negotiated rates and terms. Icahn Sourcing does not guarantee that

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)

 

CVR Refining will purchase any goods, services or property from any such vendors and CVR Refining is under no obligation to do so. CVR Refining does not pay Icahn Sourcing any fees or other amounts with respect to the buying group arrangement. CVR Refining may purchase a variety of goods and services as members of the buying group at prices and terms that management believes would be more favorable than those which could be achieved on a stand-alone basis.

(16) Subsequent Events

CVR Refining evaluated subsequent events, if any, that would require an adjustment to CVR Refining’s combined financial statements or would require disclosure in the notes to the combined financial statements through the date of issuance of the combined financial statements.

Issuance of Second Lien Senior Secured Notes and Tender Offer

On October 23, 2012, CVR Refining, LLC (“Refining LLC”) and its wholly-owned subsidiary, Coffeyville Finance Inc. (the “New Issuers”), completed a private offering of $500.0 million in aggregate principal amount of 6.500% Second Lien Senior Secured Notes due 2022 (the “2022 Notes”). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes are secured by substantially the same assets that secure the outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes have been discharged in full.

A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.3 million in aggregate amount. The remaining proceeds from the offering were used to redeem the remaining non-tendered First Lien Notes on November 23, 2012, pursuant to a notice of redemption issued on October 23, 2012. Any remaining proceeds will be used for general corporate purposes.

As a result of these transactions, a portion of the previously deferred financing charges and unamortized original issue premium will be written off in the fourth quarter of 2012. The total premiums expected to be paid in conjunction with both the tender offer and the redemption of the First Lien Notes are anticipated to be approximately $31.7 million, a portion of which will be recorded as a loss on extinguishment of debt in the fourth quarter of 2012.

A portion of the debt issuance costs of the 2022 Notes will be amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the New Issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.

Wynnewood Refinery Major Scheduled Turnaround

The Wynnewood refinery began turnaround maintenance in the fourth quarter of 2012. The Partnership expects to incur approximately $105.0 million of expenses during 2012 related to the Wynnewood refinery’s turnaround. The Wynnewood refinery has incurred $13.4 million of turnaround costs in the nine months ended September 30, 2012. It is anticipated that the downtime associated with the Wynnewood refinery turnaround will be completed, with all units at the refinery operating at full capacity, by November 30, 2012, and will significantly impact the revenue for the fourth quarter of 2012.

 

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Index to Financial Statements

Report of Independent Registered Public Accounting firm

The General Partner of CVR Refining, LP

We have audited the accompanying combined balance sheets of CVR Refining, LP (CVR Refining) as of December 31, 2011 and 2010, and the related combined statements of operations, divisional equity, and cash flows for each of the years in the three-year period ended December 31, 2011. These combined financial statements are the responsibility of CVR Refining’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of CVR Refining, LP as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

September 28, 2012

 

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Index to Financial Statements

CVR Refining, LP

COMBINED BALANCE SHEETS

 

     December 31,  
     2011      2010  
     (in thousands)  

ASSETS

     

Current assets:

     

Cash and cash equivalents

   $ 2,745       $ 2,327   

Accounts receivable, net of allowance for doubtful accounts of $1,206 and $679, respectively, including $986 and $125 from affiliates at December 31, 2011 and December 31, 2010, respectively

     174,831         75,258   

Inventories

     613,330         227,799   

Prepaid expenses and other current assets, including $881 and $767 from affiliates at December 31, 2011 and December 31, 2010, respectively

     104,096         15,781   

Insurance receivable

     1,939         —     
  

 

 

    

 

 

 

Total current assets

     896,941         321,165   

Property, plant, and equipment, net

     1,320,787         733,869   

Deferred financing costs, net

     17,154         10,601   

Insurance receivable

     4,076         3,570   

Other long-term assets, including $850 and $0 from affiliates at December 31, 2011 and December 31, 2010, respectively

     23,461         3,609   
  

 

 

    

 

 

 

Total assets

   $ 2,262,419       $ 1,072,814   
  

 

 

    

 

 

 

LIABILITIES AND DIVISIONAL EQUITY

     

Current liabilities:

     

Capital lease obligations

   $ 960       $ —     

Accounts payable, including $278 and $269 due to affiliates at December 31, 2011 and December 31, 2010, respectively

     446,840         137,874   

Personnel accruals

     9,456         6,617   

Accrued taxes other than income taxes

     28,043         14,149   

Accrued expenses and other current liabilities, including $179 and $0 due to affiliates at December 31, 2011 and December 31, 2010, respectively

     26,900         23,819   
  

 

 

    

 

 

 

Total current liabilities

     512,199         182,459   

Long-term liabilities:

     

Long-term debt and capital lease obligations, net of current portion

     728,903         468,954   

Accrued environmental liabilities, net of current portion

     1,459         2,552   

Other long-term liabilities, including $1,495 and $0 due to affiliates at December 31, 2011 and December 31, 2010, respectively

     1,232         —     
  

 

 

    

 

 

 

Total long-term liabilities

     731,594         471,506   

Commitments and contingencies (Note 14)

     

Divisional equity

     1,018,626         418,849   
  

 

 

    

 

 

 

Total liabilities and divisional equity

   $ 2,262,419       $ 1,072,814   
  

 

 

    

 

 

 

See accompanying notes to combined financial statements.

 

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Index to Financial Statements

CVR Refining, LP

COMBINED STATEMENTS OF OPERATIONS

 

     Year Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Net sales

   $ 4,752,814      $ 3,905,602      $ 2,936,539   

Operating costs and expenses:

      

Cost of product sold (exclusive of depreciation and amortization)

     3,927,620        3,539,793        2,515,928   

Direct operating expenses (exclusive of depreciation and amortization)

     247,665        153,112        142,204   

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     50,982        43,071        39,968   

Depreciation and amortization

     69,852        66,391        64,424   
  

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     4,296,119        3,802,367        2,762,524   
  

 

 

   

 

 

   

 

 

 

Operating income

     456,695        103,235        174,015   

Other income (expense):

      

Interest expense and other financing costs

     (52,995     (49,695     (43,822

Realized loss on derivatives, net

     (7,182     (2,140     (27,495

Unrealized gain (loss) on derivatives, net

     85,262        634        (37,791

Loss on extinguishment of debt

     (2,078     (16,647     (2,101

Other income, net

     578        2,832        1,835   
  

 

 

   

 

 

   

 

 

 

Total other income (expense)

     23,585        (65,016     (109,374
  

 

 

   

 

 

   

 

 

 

Net income

   $ 480,280      $ 38,219      $ 64,641   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to combined financial statements.

 

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Index to Financial Statements

CVR Refining, LP

COMBINED STATEMENTS OF CHANGES IN DIVISIONAL EQUITY

 

     Divisional
Equity
 
     (in thousands)  

Balance at December 31, 2008

   $ 405,636   

Share-based compensation

     2,508   

Contributions from parent, net

     12,615   

Net income

     64,641   
  

 

 

 

Balance at December 31, 2009

   $ 485,400   

Share-based compensation

     11,481   

Distributions to parent, net

     (116,251

Net income

     38,219   
  

 

 

 

Balance at December 31, 2010

   $ 418,849   

Share-based compensation

     8,871   

Contributions from parent, net

     110,626   

Net income

     480,280   
  

 

 

 

Balance at December 31, 2011

   $ 1,018,626   
  

 

 

 

See accompanying notes to combined financial statements.

 

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Index to Financial Statements

CVR Refining, LP

COMBINED STATEMENTS OF CASH FLOWS

 

     Year Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Cash flows from operating activities:

      

Net income

   $ 480,280      $ 38,219      $ 64,641   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     69,852        66,391        64,424   

Allowance for doubtful accounts

     527        (428     623   

Amortization of deferred financing costs

     3,872        3,356        1,941   

Amortization of original issue discount

     512        356        —     

Amortization of original issue premium

     (148     —          —     

Loss on disposition of assets

     2,661        1,606        7   

Loss on extinguishment of debt

     2,078        16,647        2,101   

Share-based compensation

     8,871        11,481        2,508   

Unrealized (gain) loss on derivatives

     (85,262     (634     37,791   

Changes in assets and liabilities:

      

Restricted cash

     —          —          34,560   

Accounts receivable

     58,892        (31,805     (16,322

Inventories

     (172,025     25,262        (130,299

Prepaid expenses and other current assets

     (14,063     (7,264     10,175   

Insurance receivable

     (2,445     (2,570     7,451   

Other long-term assets

     (1,267     (58     1,556   

Accounts payable

     7,138        39,622        14,081   

Accrued expenses and other current liabilities

     (6,916     7,085        5,672   

Payable to swap counterparty

     —          —          (65,016

Accrued environmental liabilities

     (1,093     (220     (1,439

Other long-term liabilities

     1,232        —          (2,596
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     352,696        167,046        31,859   
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Capital expenditures

     (68,826     (21,169     (34,055

Proceeds from sale of assets

     52        37        481   

Acquisition of Gary-Williams

     (587,122     —          —     
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (655,896     (21,132     (33,574
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

      

Revolving debt payments

     —          (60,000     (87,200

Revolving debt borrowings

     —          60,000        87,200   

Proceeds, gross of original issue premium on issuance of senior notes

     206,000        —          —     

Proceeds, net of original issue discount on issuance of senior notes

     —          485,693        —     

Principal payments on long-term debt

     —          (479,503     (4,825

Principal payments on senior secured notes

     (2,700     (27,500     —     

Payment of deferred financing costs

     (10,308     (8,775     (3,975

Net (distributions to) contributions from parent

     110,626        (116,251     12,615   
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     303,618        (146,336     3,815   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     418        (422     2,100   

Cash and cash equivalents, beginning of period

     2,327        2,749        649   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 2,745      $ 2,327      $ 2,749   
  

 

 

   

 

 

   

 

 

 

Supplemental disclosures:

      

Cash paid for interest net of capitalized interest of $1,091, $1,747 and $2,020 for the years ended December 31, 2011, 2010 and 2009, respectively

   $ 43,844      $ 44,770      $ 40,121   

Non-cash investing and financing activities:

      

Accrual of construction in progress additions

   $ 15,348      $ (376   $ 314   

Reduction of proceeds from senior notes for underwriting discount and financing costs

   $ 4,000      $ 10,287      $ —     

See accompanying notes to combined financial statements.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS

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

The accompanying combined Financial Statements of CVR Refining, LP (referred to as “CVR Refining” or, the “Partnership”) have been prepared in connection with the proposed initial public offering (the “Offering”) of its common units representing limited partner interests. CVR Refining is a Delaware limited partnership, formed in September 2012 by CVR Energy, Inc. (“CVR Energy”). Prior to the closing of the Offering, Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, will contribute all of its interest in the operating subsidiaries which constitute its petroleum refining and related logistics business, as well as Coffeyville Finance Inc., to a newly-formed subsidiary, CVR Refining, LLC. The operating subsidiaries that will be contributed to CVR Refining, LLC include the following entities: Wynnewood Energy Company, LLC (“WEC”); Wynnewood Refining Company, LLC (“WRC”); Coffeyville Resources Refining & Marketing, LLC (“CRRM”); Coffeyville Resources Crude Transportation, LLC (“CRCT”); Coffeyville Resources Terminal, LLC (“CRT”); and Coffeyville Resources Pipeline, LLC (“CRP”). The entities that will be contributed by CRLLC to CVR Refining in connection with the Offering are referred to herein as the “Refining Subsidiaries.” In connection with the closing of the Offering, CRLLC will contribute its 100% membership interest in CVR Refining, LLC to the Partnership in exchange for the issuance of a designated number of common units of the Partnership to CVR Refining Holdings, LLC, a wholly-owned subsidiary of CRLLC. CRLLC will retain its other assets, including common units representing a 69.7% limited partner interest in CVR Partners, LP (“CVR Partners”), a New York Stock Exchange traded manufacturer of nitrogen fertilizer, and a 100% membership interest in CVR GP, LLC, the general partner of CVR Partners.

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

The Partnership’s general partner, CVR Refining GP, LLC, will manage the Partnership’s activities subject to the terms and conditions specified in the Partnership’s partnership agreement. The Partnership’s general partner will be owned by CVR Refining Holdings, LLC. The operations of the general partner, in its capacity as general partner will be managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CVR Refining Holdings LLC as the sole member of the Partnership’s general partner and not by the board of directors of the general partner. The Partnership’s general partner will not be elected by the Partnership’s unitholders and will not be subject to re-election on a regular basis in the future. The officers of the general partner will manage the day-to-day affairs of the business.

On the closing date of the Offering, the Partnership will enter into a services agreement, pursuant to which the Partnership and its general partner will obtain certain management and other services from CVR Energy, and an omnibus agreement, pursuant to which the Partnership will agree not to, and will cause its controlled affiliates not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of crude oil or refined products in the contiguous United States, or a refining restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of the Partnership’s outstanding units.

(2) Basis of Presentation

The accompanying financial statements have been prepared in accordance with Regulation S-X, Article 3, “General instructions as to financial statements” and Staff Accounting Bulletin, or SAB Topic 1-B, “Allocations of Expenses and Related disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Components of Another Entity.” Certain expenses incurred by CVR Energy are only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. As a result, certain assumptions and estimates are made in order to allocate a reasonable share of such expenses to CVR Refining, so that the accompanying financial statements reflect substantially all costs of doing business. The allocations and related estimates and assumptions are described more fully in Note 3 (“Summary of Significant Accounting Policies”) and Note 17 (“Related Party Transactions”).

CRLLC used a centralized approach to cash management and the financing of its operations. As a result, amounts owed to or from CRLLC are reflected as a component of divisional equity on the accompanying Combined Statements of changes in Divisional Equity.

Accounts and balances related to the refining and related logistics operations were based on a combination of specific identification and allocations. CVR Energy and CRLLC has allocated various corporate overhead expenses based on a percentage of total refining and related logistics payroll to the total payrolls of its segments (i.e., the petroleum and fertilizer segments are comprised of CVR Refining and CVR Partners, respectively). These allocations are not necessarily indicative of the cost that the Partnership would have incurred had it operated as an independent stand-alone entity for all years presented. All intercompany accounts and transactions have been eliminated.

(3) Summary of Significant Accounting Policies

Cash and Cash Equivalents

CRLLC has historically provided cash as needed to support the operations of the refining and related logistics assets and has retained excess cash earned by the Partnership. The Partnership considers all highly liquid money market accounts and debt instruments with original maturities of three months or less to be cash equivalents. Cash received or paid by CRLLC on behalf of CVR Refining is reflected as net contributions from or net distributions to parent on the accompanying combined Statements of Changes in Divisional Equity.

Accounts Receivable, net

CVR Refining grants credit to its customers. Credit is extended based on an evaluation of a customer’s financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding longer than their contractual payment terms are considered past due. CVR Refining determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer’s ability to pay its obligations to CVR Refining, and the condition of the general economy and the industry as a whole. CVR Refining writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided by operating activities in the combined Statements of Cash Flows. At December 31, 2011, no customer individually represented greater than 10% of the total accounts receivable balance. At December 31, 2010, two customers individually represented greater than 10% and collectively represented 22% of the total accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2011 and 2010 was approximately 9% and 12%, respectively, of the accounts receivable balance.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Inventories

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

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to our refineries for which title had not transferred, non-trade accounts receivables, current portions of prepaid insurance and deferred financing costs, and other general current assets.

Property, Plant, and Equipment

Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1.0 million in cost which is expected to take more than six months to complete. Depreciation is computed using principally the straight-line method over the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:

 

Asset

   Range of Useful
Lives, in Years
 

Improvements to land

     15 to 30   

Buildings

     20 to 30   

Machinery and equipment

     5 to 30   

Automotive equipment

     5 to 15   

Furniture and fixtures

     3 to 10   

Leasehold improvements are depreciated or amortized on the straight-line method over the shorter of the contractual lease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in CVR Refining’s combined Statements of Operations.

Deferred Financing Costs, Underwriting and Original Issue Discount

Deferred financing costs related to the first priority term debt credit facility and senior secured notes are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Additionally, the underwriting and original issue discount and premium related to the issuance of the senior secured notes are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to the first priority revolving credit facility and ABL credit facility are amortized to interest expense and other financing costs using the straight-line method through the termination date of the respective facility. Deferred financing costs related to the first priority funded letter of credit facility were amortized to interest expense and other financing costs using the straight-line method through the termination of the facility in October 2009.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Planned Major Maintenance Costs

The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. During the year ended December 31, 2011, the Coffeyville refinery completed the first phase of a two-phase major scheduled turnaround. Costs of approximately $66.4 million and $1.2 million associated with the Coffeyville refinery’s 2011 turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the years ended December 31, 2011 and 2010, respectively.

Planned major maintenance activities for the refineries varies by unit, but generally is every four to five years. The Wynnewood refinery’s next major maintenance activities are scheduled for the fourth quarter of 2012.

Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $2.4 million, $2.8 million and $2.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses also include allocated non-cash share-based compensation for CVR Energy and Coffeyville Acquisition III LLC (“CALLC III”), as discussed in Note 5 (“Share-Based Compensation”). Direct operating expenses exclude depreciation and amortization of approximately $67.3 million, $63.4 million and $61.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate and administrative offices in Texas and in Kansas. Selling, general and administrative expenses also include allocated non-cash share-based compensation expense from CVR Energy and CALLC III as discussed in Note 5 (“Share-Based Compensation”). Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.2 million, $0.2 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Income Taxes

The operations of CVR Refining have historically been included in the federal income tax return of CRLLC, which is a limited liability company that is not subject to federal income tax. Upon the sale of common units in the Offering, CVR Refining will file its own separate federal income tax return with each partner being separately taxed on its share of taxable income. The Partnership will not be subject to income taxes except for a franchise tax in the state of Texas. The income tax liability of the individual partners will not be reflected in the combined financial statements of the Partnership.

Segment Reporting

The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 280—Segment Reporting, established standards for entities to report information about the operating segments and geographic areas in which they operate. CVR Refining only operates one segment and all of its operations are located in the United States.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Impairment of Long-Lived Assets

CVR Refining accounts for long-lived assets in accordance with accounting standards issued by FASB regarding the treatment of the impairment or disposal of long-lived assets. As required by this standard, CVR Refining reviews long-lived assets (excluding intangible assets with indefinite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell.

Divisional Equity

Partners’ capital is referred to as divisional equity during the periods covered by the combined financial statements prior to the contribution of the Refining Subsidiaries to the Partnership. Once the Refining Subsidiaries are contributed to the Partnership, divisional equity will become partners’ capital.

Revenue Recognition

Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has assumed the risk of loss, and payment has been received or collection is reasonably assumed. Excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.

Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the combined Statement of Operations.

The Partnership also engages in trading activities, whereby the Partnership enters into agreements to purchase and sell refined products with third parties. The Partnership acts as a principal in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards of ownership. The Partnership records revenue for the gross amount of the sales transactions, and records costs of purchases as an operating expense in the accompanying combined financial statements.

Shipping Costs

Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciation and amortization).

Derivative Instruments and Fair Value of Financial Instruments

The Partnership uses futures contracts, options, and forward swap contracts primarily to reduce the exposure to changes in crude oil prices, finished goods product prices and interest rates and to provide economic hedges of inventory positions. These derivative instruments have not been designated as hedges for accounting purposes. Accordingly, these instruments are recorded in the combined Balance Sheets at fair value, and each period’s gain or loss is recorded as a component of realized gain (loss) on derivatives, net or unrealized gain (loss) on derivatives, net, as applicable, in accordance with standards issued by the FASB regarding the accounting for derivative instruments and hedging activities.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. See Note 12 (“Long-Term Debt”) for further discussion of the extinguishment of the first priority credit facility long-term debt and issuance of senior secured notes. The senior secured notes are carried at the aggregate principal value less the unamortized original issue discount and premium. See Note 12 (“Long-Term Debt”) for the fair value of the senior secured notes.

Share-Based Compensation

The Partnership has been allocated non-cash share-based compensation expense from CVR Energy, CRLLC and from CALLC III. CVR Energy accounts for share-based compensation in accordance with ASC 718 Compensation—Stock Compensation, or ASC 718, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. In accordance with ASC 718, CVR Energy, CRLLC and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. The Partnership recognizes the costs of the share-based compensation incurred by CVR Energy and CALLC III on the Partnership’s behalf primarily in selling, general and administrative expenses (exclusive of depreciation and amortization), and a corresponding increase or decrease to divisional equity, as the costs are incurred on its behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees for acquiring, or in conjunction with selling, goods or services, which require remeasurement at each reporting period through the performance commitment period, or in the Partnership’s case, through the vesting period. Costs are allocated by CVR Energy and CALLC III based upon the percentage of time a CVR Energy or CRLLC employee provides services to the Partnership CRLLC.

Environmental Matters

Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.

Use of Estimates

The combined financial statements have been prepared in conformity with U. S. generally accepted accounting principles, using management’s best estimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from these estimates and judgments.

Related Party Transactions

CVR Energy and its subsidiaries provide a variety of services to CVR Refining, including cash management and financing services, employee benefits provided through CVR Energy’s benefit plans, administrative services provided by CVR Energy’s employees and management, insurance and office space leased in CVR Energy’s headquarters building and other locations. As such, the accompanying combined financial statements include costs that have been incurred by CVR Energy and CRLLC on behalf of CVR Refining. These amounts incurred by CVR Energy are then billed or allocated to CVR Refining and are properly classified on the combined

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Statements of Operations as either direct operating expenses (exclusive of depreciation and amortization) or as selling, general and administrative expenses (exclusive of depreciation and amortization). Such expenses include, but are not limited to, salaries, benefits, share-based compensation expense, insurance, accounting, tax, legal and technology services. Where costs are specifically incurred on behalf of CVR Refining, the costs are billed directly to CVR Refining. See Note 17 (“Related Party Transactions”) for a detailed discussion of the billing procedures and the basis for calculating the charges.

Allocation of Costs

The accompanying financial statements have been prepared in accordance with SAB Topic 1-B, as more fully explained in Note 2. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. CVR Energy and CRLLC has allocated general and administrative expenses to CVR Refining based on allocation methodologies that management considers reasonable and result in an allocation of the cost of doing business borne by CVR Energy and CRLLC on behalf of CVR Refining; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

CVR Refining’s historical combined Statements of Operations reflect all of the expenses that CRLLC and CVR Energy incurred on CVR Refining’s behalf. CVR Refining’s financial statements therefore include certain expenses incurred by CVR Energy and CRLLC which may include, but are not necessarily limited to, the following:

 

   

Officer and employee salaries and share-based compensation;

 

   

Rent or depreciation;

 

   

Advertising;

 

   

Accounting, tax, legal and information technology services;

 

   

Other selling, general and administrative expenses;

 

   

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

 

   

Financing costs, including interest, mark-to-market changes in interest rate swap, and losses on extinguishment of debt.

Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining as governed by percentages determined by management to be reasonable and in line with the nature of an individual’s roles and responsibilities. Allocations related to share-based compensation are more fully described in Note 5 (“Share-Based Compensation”). Property insurance costs, included in direct operating expenses (exclusive of depreciation and amortization), were allocated based upon specific segment valuations. See Note 17 (“Related Party Transactions”) for a detailed discussion of transactions with affiliated entities. The table below reflects cost allocations, either allocated or billed, by period reflected in the combined Statement of Operations.

 

     Year Ended December 31,  
     2011      2010      2009  

Direct operating expenses (exclusive of depreciation and amortization)

   $ 9,064       $ 9,789       $ 10,971   

Selling, general and administrative expenses (exclusive of depreciation and amortization)

     39,723         35,347         33,833   
  

 

 

    

 

 

    

 

 

 
   $ 48,787       $ 45,136       $ 44,804   
  

 

 

    

 

 

    

 

 

 

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Net Income Per Unit

CVR Refining has omitted earnings per unit because CVR Refining has operated under a divisional equity structure.

New Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U. S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U. S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U. S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. CVR Refining believes that the adoption of this standard will not materially expand its combined financial statement footnote disclosures.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U. S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for interim and annual periods beginning January 1, 2013. CVR Refining believes this standard will expand its combined financial statement footnote disclosures.

(4) Wynnewood Acquisition

On December 15, 2011, CVR Refining, through CRLLC, completed the acquisition of all the issued and outstanding shares of the Gary-Williams Energy Corporation (subsequently converted to WEC), including its two wholly-owned subsidiaries (the “Wynnewood Acquisition”), for a purchase price of $593.4 million from The Gary-Williams Company, Inc. (the “Seller”). This consisted of $525.0 million, in cash, plus approximately $66.6 million for working capital and approximately $1.8 million for a capital expenditure adjustment. The Wynnewood Acquisition was partially funded by proceeds received from the issuance of additional 9.0% First Lien Senior Secured Notes. See Note 12 (“Long-Term Debt”) for further discussion of the issuance. The Wynnewood Acquisition was accounted for under the purchase method of accounting and, as such, CVR Refining’s results of operations on the combined Statement of Operations for the year ended December 31, 2011 include WEC’s revenues and loss before income taxes of approximately $115.7 million and $2.3 million, respectively, for the period from December 16, 2011 through December 31, 2011.

WEC owns a 70,000 bpd refinery in Wynnewood, Oklahoma that includes approximately 2.0 million barrels of company-owned storage tanks. Located in the PADD II Group 3 distribution area, the Wynnewood refinery is a dual crude oil unit facility that processes a variety of crudes and produces high-value fuel products (including gasoline, ultra-low sulfur diesel, jet fuel and solvent) as well as liquefied petroleum gas and a variety of asphalts.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Purchase Price Allocation

Under the purchase method of accounting, the total purchase price was allocated to WEC’s net tangible assets based on their fair values as of December 15, 2011. An independent appraisal of the net assets was completed. The following table displays the total purchase price allocated to WEC’s net tangible assets based on their fair values as of December 15, 2011 (in millions):

 

Cash and cash equivalents

   $ 6.3   

Receivables

     159.0   

Inventories

     213.5   

Prepaid and other current assets

     6.0   

Property, plant and equipment

     575.0   

Accounts payable and accrued liabilities

     (314.1

Long-term debt

     (52.3
  

 

 

 

Total fair values of net assets acquired

     593.4   
  

 

 

 

Less: cash acquired

     6.3   
  

 

 

 

Total consideration transferred, net of cash acquired

   $ 587.1   
  

 

 

 

In accordance with the Stock Purchase and Sale Agreement (the “Purchase Agreement”), CVR Refining provided a Post-Closing Statement to the Seller on February 13, 2012 which reflects the difference between the cash paid at closing for the estimated working capital and the estimated capital expenditure adjustment as compared to CVR Refining’s calculation of the actual working capital and capital expenditure adjustment at the closing of the Wynnewood Acquisition. This final difference in the cash paid at closing and the final purchase price of approximately $14.7 million and was received in May 2012.

Acquisition Costs

As of December 31, 2011, the Partnership has recognized approximately $5.2 million in transaction fees and preliminary integration expenses that are included in selling, general and administrative expense in the combined Statement of Operations. These costs primarily relate to legal, accounting, initial purchaser discounts and commissions, and other professional fees incurred since the announcement of the Wynnewood Acquisition in November 2011. In addition, CVR Refining, through CRLLC, entered into a commitment letter for a senior secured one-year bridge loan to ensure that financing would be available for the Wynnewood Acquisition in the event that the additional offering of First Lien Notes was not closed by the date of the Wynnewood Acquisition. The bridge loan was never drawn. A commitment fee and other third-party costs totaling $3.9 million are included in selling, general and administrative expenses associated with the undrawn bridge loan.

(5) Share-Based Compensation

Certain employees of CVR Refining and employees of CVR Energy who perform services for CVR Refining participate in the equity compensation plans of CVR Refining’s affiliates. Accordingly, CVR Refining has recorded compensation expense for these plans in accordance with SAB Topic 1-B and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Refining has been allocated 100% to CVR Refining. For employees of CVR Energy performing services for CVR Refining, CVR Refining recorded share-based compensation relative to the percentage of time spent by each employee providing services to CVR Refining as compared to the total calculated share-based compensation by CVR Energy. CVR Refining is not responsible for payment of share-based compensation and all expense amounts are reflected as an increase or decrease to divisional equity.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Prior to CVR Energy’s initial public offering, CVR Energy’s subsidiaries were held and operated by Coffeyville Acquisition LLC (“CALLC”). CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR Energy’s initial public offering in October 2007, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”). In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. In addition, in connection with the transfer of the managing general partner of CVR Partners to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

For the years ended December 31, 2011, 2010 and 2009, the estimated fair value of the override units of CALLC and CALLC II were derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the then current value of CVR Energy’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are vested.

The final fair value of the CALLC III override units was derived based upon the aggregate principal amount of the proceeds received by CVR Partners’ general partner upon the purchase of CVR Partners’ incentive distribution rights (“IDRs”) by CVR Partners. These proceeds were subsequently distributed to the owners of CALLC III which includes the override unitholders. This value was utilized to determine the related compensation expense for the unvested units. No additional share-based compensation has been or will be incurred with respect to override units of CALLC III following the year ended December 31, 2011 due to the complete distribution of the value during that year. For the year ended December 31, 2010, the estimated fair value of the CALLC III override units was determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and also considered the pending initial public offering of CVR Partners, including the purchase of CVR Partners’ managing GP interest (including the IDRs). For the year ended December 31, 2009, the estimated fair value of the override units of CALLC III was determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections, which were considered representative of the nature of interests held by CALLC III in CVR Partners.

In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR Energy’s common stock, pursuant to a registered public offering. In May 2011, CALLC sold into the public market 7,988,179 shares of CVR Energy’s common stock, pursuant to a registered public offering.

As a result, CALLC and CALLC II ceased to be stockholders of CVR Energy. Subsequent to CALLC II’s divestiture of its ownership interest in CVR Energy in February 2011 and CALLC’s divestiture of its ownership interest in CVR Energy in May 2011, no additional share-based compensation expense was incurred with respect to override units and phantom units after each respective divestiture date. The final fair values of the override units of CALLC and CALLC II were derived based upon the values resulting from the proceeds received associated with each entity’s respective divestiture of its ownership in CVR Energy. These values were utilized to determine the related compensation expense for the unvested units.

 

F-44


Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III.

 

Award Type

  Benchmark
Value
(per Unit)
    Original
Awards
Issued
          *Compensation Expense  Increase
(Decrease) for the Year Ended
December 31,
 
      Grant Date         2011             2010             2009      
                      (in thousands)  

Override Operating Units(a)

  $ 11.31        919,630        June 2005      $ —        $ 104      $ 652   

Override Operating Units(b)

  $ 34.72        72,492        December 2006        —          2        4   

Override Value Units(c)

  $ 11.31        1,839,265        June 2005        1,353        5,199        866   

Override Value Units(d)

  $ 34.72        144,966        December 2006        (4     58        4   

Override Units(e)

  $ 10.00        642,219        February 2008        (94     (244     20   
       

 

 

   

 

 

   

 

 

 
        Total      $ 1,255      $ 5,119      $ 1,546   
       

 

 

   

 

 

   

 

 

 

 

* As CVR Energy’s common stock price increased or decreased, compensation expense associated with the unvested CALLC and CALLC II override units increased or was reversed in correlation with the calculation of the fair value under the probability-weighted expected return method.

Due to the divestiture of all ownership in CVR Energy by CALLC and CALLC II and due to the purchase of the IDRs from CVR Partners’ general partner and the distribution to CALLC III, there was no associated unrecognized compensation expense as of December 31, 2011.

Valuation Assumptions

Significant assumptions used in the valuation of the Override Operating Units (a) and (b) were as follows:

 

     (a) Override Operating Units     (b) Override Operating Units  
     December 31, 2009     December 31, 2009  

Estimated forfeiture rate

     None        None   

CVR Energy closing stock price

   $ 6.86      $ 6.86   

Estimated fair value (per unit)

   $ 11.95      $ 1.40   

Marketability and minority interest discounts

     20.0     20.0

Volatility

     50.7     50.7

As of December 31, 2010 these override units were fully vested.

Significant assumptions used in the valuation of the Override Value Units (c) and (d) were as follows:

 

     (c) Override Value Units
December 31,
    (d) Override Value Units
December 31,
 
             2010                     2009                     2010                     2009          

Estimated forfeiture rate

     None        None        None        None   

Derived service period

     6 years        6 years        6 years        6 years   

CVR Energy closing stock price

   $ 15.18      $ 6.86      $ 15.18      $ 6.86   

Estimated fair value (per unit)

   $ 22.39      $ 5.63      $ 6.56      $ 1.39   

Marketability and minority interest discounts

     20.0     20.0     20.0     20.0

Volatility

     43.0     50.7     43.0     50.7

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

(e) Override Units—Using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and included expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR Energy also recognized income equal to the amount that its interest in the investee’s net book value increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units were subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:

 

     December
     2010   2009

Estimated forfeiture rate

   None   None

Derived Service Period

   Based on forfeiture schedule   Based on forfeiture schedule

Estimated fair value (per unit)

   $2.60   $0.08

Marketability and minority interest discount

   10.0%   20.0%

Volatility

   47.6%   59.7%

Phantom Unit Plans

CVR Energy, through CRLLC, had two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees and service providers were awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points had rights to receive distributions when holders of override operating units received distributions. Holders of performance phantom points had rights to receive distributions when CALLC and CALLC II holders of override value units received distributions.

Compensation expense allocated for the years ended December 31, 2011, 2010 and 2009 related to the Phantom Unit Plans was approximately $4.3 million, $5.9 million and $0.9 million, respectively. Due to the divestiture of all ownership of CVR Energy by CALLC and CALLC II, there was no unrecognized compensation expense associated with the Phantom Unit Plans at December 31, 2011.

Expense for these awards was based on fair value, which was derived from a probability-weighted expected return method. Using CVR Energy’s closing stock price at December 31, 2010 and 2009 to determine the company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interests were valued as follows:

 

     December 31,  
     2010      2009  

Service phantom interest (per point)

   $ 14.64       $ 11.37   

Performance phantom interest (per point)

   $ 21.25       $ 5.48   

Long-Term Incentive Plan—CVR Energy

CVR Energy has a Long-Term Incentive Plan (“CVR Energy LTIP”) that permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock). As of December 31, 2011, only restricted shares of CVR Energy common stock and stock options had been granted under the CVR Energy LTIP. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy’s or its subsidiaries’ (including CVR Refining) employees, officers, consultants and directors.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Restricted Shares

Through the CVR Energy LTIP, shares of restricted common stock have been granted to employees of CVR Energy and CVR Refining. Restricted shares, when granted, are valued at the closing market price of CVR Energy’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the common stock. These shares generally vest over a three-year period. Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2011, there was approximately $11.4 million of total unrecognized compensation cost related to restricted shares to be recognized over a weighted-average period of approximately two years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that occur from time to time. The unrecognized compensation expense has been determined by the number of restricted shares and respective allocation percentage for individuals for whom, as of December 31, 2011, compensation expense has been allocated to the Partnership.

Compensation expense recorded for the years ended December 31, 2011, 2010 and 2009, related to the restricted shares, was approximately $3.3 million, $0.5 million and $0.1 million, respectively.

(6) Inventories

Inventories consisted of the following:

 

     December 31,  
     2011      2010  
     (in thousands)  

Finished goods

   $ 316,654       $ 107,060   

Raw materials and precious metals

     154,530         85,814   

In-process inventories

     115,090         22,913   

Parts and supplies

     27,056         12,012   
  

 

 

    

 

 

 
   $ 613,330       $ 227,799   
  

 

 

    

 

 

 

(7) Property, Plant, and Equipment

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

 

     December 31,  
     2011      2010  
     (in thousands)  

Land and improvements

   $ 19,193       $ 12,478   

Buildings

     33,887         23,079   

Machinery and equipment

     1,570,191         966,481   

Automotive equipment

     9,603         8,164   

Furniture and fixtures

     5,713         3,142   

Leasehold improvements

     413         220   

Construction in progress

     39,781         8,497   
  

 

 

    

 

 

 
     1,678,781         1,022,061   

Accumulated depreciation

     357,994         288,192   
  

 

 

    

 

 

 

Total net, property, plant and equipment

   $ 1,320,787       $ 733,869   
  

 

 

    

 

 

 

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2011, 2010 and 2009 totaled approximately $1.1 million, $1.8 million and $2.0 million, respectively. Land, building and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million, $0 and $0 for the years ended December 31, 2011, 2010 and 2009, respectively.

(8) Deferred Financing Costs and Original Issue Discount

As discussed in detail in Note 12, CRLLC issued senior secured notes in 2011 and 2010. As the senior secured notes were incurred for the benefit of the operations of CVR Refining, all the debt and associated costs have been allocated to CVR Refining in these combined financial statements.

On December 15, 2011, CRLLC issued an additional $200.0 million of senior secured notes for the benefit of CVR Refining, as described below. An original issue premium of $10.0 million was received related to the issuance which is being amortized using the interest method over the remaining term of the senior secured notes. In connection with this issuance, CRLLC paid an underwriting discount of $4.0 million and third-party costs of approximately $2.0 million which are being amortized as interest expense using the effective-interest method over the remaining term of the senior secured notes.

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc., completed a private offering of senior secured notes that had an aggregate principal amount of $500 million. The proceeds of the offering were utilized to extinguish the existing long-term debt under the first priority credit facility. As a result of the extinguishment, CVR Refining wrote-off approximately $5.4 million of previously deferred financing costs. In connection with this issuance of the senior secured notes, CRLLC incurred approximately $3.9 million of third-party costs. Of these costs, approximately $30,000 was immediately expensed and the remaining approximately $3.9 million was deferred and will be amortized as interest expense using the effective-interest method. In addition, CVR Refining incurred an underwriting discount of $10 million. Of these costs approximately $76,000 were immediately expensed at the time of issuance following the accounting standards relating to the modification of debt instruments by debtors. The remaining balance of approximately $9.9 million is being amortized as interest expense using the effective-interest method over the term of the senior secured notes. On December 30, 2010, CVR Refining made an unscheduled voluntary prepayment of its senior secured notes of approximately $27.5 million. In connection with the voluntary prepayment, CVR Refining wrote off a portion of previously deferred financing costs and unamortized original issue discount of approximately $0.8 million. As a result of the extinguishment of CVR Refining’s long-term debt under the first priority credit facility, the issuance of senior secured notes and voluntary unscheduled prepayment on the senior secured notes, CVR Refining recorded a total loss on extinguishment of debt of approximately $6.3 million for the year ended December 31, 2010. In addition, as described in further detail in Note 12 (“Long-Term Debt”), CVR Refining also recorded additional losses on extinguishment of debt of approximately $10.4 million in connection with premiums paid for the early extinguishment of debt for the year ended December 31, 2010.

On May 16, 2011, CRLLC repurchased $2.7 million of the senior secured notes at a purchase price of 103% of the outstanding principal amount. In connection with the repurchase, CRLLC wrote off a portion of previously deferred financing costs and unamortized original issue discount of approximately $89,000 which is recorded as a loss on extinguishment of debt for the year ended December 31, 2011. CVR Refining also recorded additional losses on extinguishment of debt of $81,000 in connection with premiums paid for the repurchase.

On March 12, 2010, CRLLC entered into a fourth amendment to its outstanding first priority credit facility for the benefit of the operations of CVR Refining. In connection with this amendment, CVR Refining paid approximately $6.0 million of lender and third party costs. CVR Refining recorded an expense of approximately

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

$1.1 million primarily associated with third-party costs in 2010. The remaining costs incurred of approximately $4.9 million were deferred to be amortized as interest expense using the effective-interest method for the first priority credit facility long-term debt and the straight-line method for the first priority revolving credit facility.

On October 2, 2009, CRLLC entered into a third amendment to its outstanding first priority credit facility. In connection with this amendment, CVR Refining paid approximately $4.0 million of lender and third-party costs. CVR Refining recorded an expense of approximately $1.0 million primarily associated with third-party costs in 2009. The remaining costs incurred of approximately $3.0 million were deferred to be amortized as interest expense using the effective-interest method for the first priority credit facility long-term debt and the straight-line method for the first priority revolving credit facility. In connection with the reduction and eventual termination of the first priority funded letter of credit facility on October 15, 2009, CVR Refining recorded a loss on the extinguishment of debt of approximately $2.1 million for the year ended December 31, 2009. The loss on extinguishment of debt is attributable to amounts previously deferred at the time of the original credit facility, as well as amounts deferred at the time of the second and third amendments.

For the years ended December 31, 2011, 2010 and 2009, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $4.2 million, $3.7 million and $1.9 million, respectively.

Estimated amortization of deferred financing costs is as follows:

 

Year Ending December 31,

   Deferred Financing  
     (in thousands)  

2012

     6,416   

2013

     6,409   

2014

     6,409   

2015

     3,225   

2016

     879   

Thereafter

     232   
  

 

 

 
   $ 23,570   
  

 

 

 

(9) Capital Lease Obligation

As a result of the Wynnewood Acquisition, CVR Refining assumed two leases accounted for as a capital lease and a finance obligation related to the Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The two arrangements have remaining terms of 213 and 214 months respectively. As of December 31, 2011, the outstanding obligation associated with these arrangements totaled approximately $53.2 million. See Note 12 (“Long-Term Debt”).

(10) Flood

For the years ended December 31, 2011, 2010 and 2009, CVR Refining recorded pre-tax expenses, net of anticipated insurance recoveries of approximately $1.5 million, $(1.0) million and $0.6 million, respectively, associated with the Coffeyville June/July 2007 flood and associated crude oil discharge. The costs are reported in direct operating expenses in the combined Statements of Operations. With the final insurance proceeds received under CVR Refining’s property insurance policy and builders’ risk policy during the first quarter of 2009, in the amount of approximately $7.5 million, all property insurance claims and builders’ risk claims were fully settled, with all remaining claims closed under these policies only.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

At December 31, 2011, the remaining receivable from the environmental insurance carriers was not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset. See Note 14 (“Commitments and Contingencies”) for additional information regarding environmental and other contingencies related to the crude oil discharge that occurred on July 1, 2007.

(11) Insurance Claims

On December 28, 2010 the Coffeyville crude oil refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (“FCCU”), which led to reduced crude oil throughput. The refinery returned to full operation on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of December 31, 2011 were approximately $8.0 million.

CVR Refining maintains property damage insurance policies through CRLLC which have an associated deductible of $2.5 million. CVR Refining anticipates that substantially all of the repair costs in excess of the deductible should be covered by insurance. As of December 31, 2011, CVR Refining has received approximately $4.0 million of insurance proceeds and has recorded an insurance receivable related to the incident of approximately $1.2 million. The insurance receivable is included in current assets in the combined Balance Sheet. The recording of the insurance proceeds and receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

The Coffeyville crude oil refinery experienced a small fire at its continuous catalytic reformer (“CCR”) in May 2011. Total gross repair and other costs related to the incident that were recorded during the year ended December 31, 2011 approximated $3.2 million. CVR Refining anticipates that substantially all of the costs in excess of the $2.5 million deductible should be covered by insurance under its property damage insurance policy. As of December 31, 2011, CVR Refining has recorded an insurance receivable of approximately $0.7 million. The insurance receivable is included in current assets in the combined Balance Sheet. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

(12) Long-Term Debt

Long-term debt balances as of December 31, 2011 and 2010 were as noted below. As of December 31, 2011 and 2010 there was $17.0 million and $12.2 million, respectively, of accrued interest related to our debt obligations included in accrued expenses and other current liabilities on the combined Balance Sheets.

 

     December 31,  
     2011      2010  
     (in thousands)  

9.0% Senior Secured Notes, due 2015, net of unamortized premium of $9,003(1) as of December 31, 2011 and unamortized discount of $1,065 as of December 31, 2010

   $ 456,053       $ 246,435   

10.875% Senior Secured Notes, due 2017, net of unamortized discount of $2,159 and $2,481 as of December 31, 2011 and December 31, 2010, respectively

     220,591         222,519   

Capital lease obligations

     52,259         —     
  

 

 

    

 

 

 

Long-term debt

   $ 728,903       $ 468,954   
  

 

 

    

 

 

 

 

(1) Net unamortized premium of $9.0 million represents an unamortized discount of $0.9 million on the original First Lien Notes and a $9.9 million unamortized premium on the additional First Lien Notes issued in December 2011.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Senior Secured Notes

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Notes is amortized to interest expense and other financing costs over the respective term of the Notes. On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of approximately $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million, which was recognized as a loss on extinguishment of debt in the combined Statements of Operations for the year ended December 31, 2010. On May 16, 2011, CRLLC repurchased $2.7 million of the Notes at a purchase price of 103.0% of the outstanding principal amount, which resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized issue discount. As the Notes were incurred for the benefit of the operations of CVR Refining, all the debt and associated costs have been allocated to CVR Refining. See Note 8 (“Deferred Financing Costs, Underwriting and Original Issue Discount”) for further discussion of the related debt issuance costs. At December 31, 2011, the carrying value of the original First Lien Notes was $246.2 million, net of unamortized discount of approximately $0.8 million. At December 31, 2010, the carrying value of the original First Lien Notes was $246.4 million, net of unamortized discount of $1.1 million.

CRLLC received total net proceeds from the offering of approximately $485.7 million, net of underwriter fees of $10 million and original issue discount of approximately $4.0 million and certain third party fees of $287,000. In addition, CRLLC incurred additional third party fees and expenses, totaling $3.6 million associated with the offering. CRLLC applied the net proceeds to prepay all of the outstanding balance of its tranche D term loan under its first priority credit facility in an amount equal to approximately $453.3 million and to pay related fees and expenses. In accordance with the terms of its first priority credit facility, CRLLC paid a 2.0% premium totaling approximately $9.1 million to the lenders of the tranche D term loan upon the prepayment of the outstanding balance. This amount was recorded as a loss on extinguishment of debt during the second quarter of 2010. This premium was in addition to the 2.0% premium totaling $0.5 million paid in the first quarter of 2010 for voluntary unscheduled prepayments of $25.0 million on CRLLC’s tranche D term loan. This premium was recognized as a loss on extinguishment of debt in the first quarter of 2010. The related original issue discount and debt issuance costs of the Notes are being amortized over the term of the applicable Notes.

On December 15, 2011, the Issuers issued an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “New Notes”). The New Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of the New Notes is amortized to interest expense and other financing costs over the respective term of the New Notes. The New Notes were issued as “Additional Notes” pursuant to an indenture dated April 6, 2010 (the “Indenture”) and, together with the existing first lien notes, are treated as a single class for all purposes under the Indenture including, without limitation, waivers, amendments, redemptions and other offers to purchase. Unless otherwise indicated, the New Notes and the existing first lien notes are collectively referred to herein as the “First Lien Notes”. Proceeds of the New Notes were used to partially fund the Wynnewood Acquisition. On November 2, 2011, CRLLC entered into a commitment letter with certain lenders regarding a senior secured one year bridge loan (“the bridge loan”). CRLLC entered into the commitment letter in connection with ensuring that financing would be available for the Wynnewood Acquisition in the event that the offering of the New Notes was not closed by the date of closing of the Wynnewood Acquisition. Due to the closing of the issuance of the New Notes, the bridge loan was never drawn. At the closing of the issuance of the New Notes and the Wynnewood

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Acquisition, a commitment fee was paid to the lenders who provided the commitment. Other third-party costs were incurred. All costs associated with the undrawn bridge loan were fully expensed. In conjunction with the issuance of the New Notes, CRLLC expanded the existing ABL credit facility (see “ABL Credit Facility” below for further discussion of the expansion and associated accounting treatment) and incurred a commitment fee and other third-party costs associated with the expansion. At December 31, 2011, the carrying value of the additional First Lien Notes was $209.9 million, net of unamortized premium of $9.9 million.

CRLLC received total net proceeds from the offering of approximately $202.8 million, net of an underwriting discount of $4.0 million, bridge loan commitment and other associated fees of $3.3 million, an ABL commitment fee of $2.6 million, a New Notes structuring fee of $0.2 million, and certain third party fees of $0.8 million. The related original issue premium and other debt issuance costs related to the New Notes are being amortized over the remaining term of the First Lien Notes. Fees and third-party costs totaling $3.9 million related to the undrawn bridge loan were expensed for the year ended December 31, 2011 and are included in selling, general and administrative expenses (exclusive of depreciation and amortization) on the combined Statements of Operations. Fees and third-party costs associated with the ABL credit facility expansion are being amortized over the remaining term of the facility.

The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year, commencing on October 1, 2010. Included in other current liabilities on the combined Balance Sheet is accrued interest payable totaling approximately $16.1 million and $11.8 million for the years ended December 31, 2011 and 2010, respectively, related to the Notes. Of this amount, $3.7 million represents cash received from the New Notes offering for accrued interest for the period October 1, 2011 through December 15, 2011. At December 31, 2011, the estimated fair value of the First and Second Lien Notes was approximately $473.9 million and $249.5 million, respectively. These estimates of fair value are level 2 as they were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC’s subsidiaries other than CVR Partners and CRNF.

ABL Credit Facility

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (the “ABL credit facility”) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility is scheduled to mature in August 2015 and replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility will be used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of CVR Refining and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to additional lender commitments. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase the borrowings under the ABL credit facility to $400.0 million in the aggregate in connection with the New Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. As of December 31, 2011, CRLLC had availability under the ABL credit facility of $313.9 million and had letters of credit outstanding of approximately $86.1 million. There were no borrowings outstanding under the ABL credit facility as of December 31, 2011.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

The ABL credit facility contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, the incurrence of liens on assets, and the ability to dispose of assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. The ABL credit facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. As of December 31, 2011, CRLLC was in compliance with the covenants contained in the ABL credit facility.

In connection with the ABL credit facility, CRLLC incurred lender and other third-party costs of approximately $9.1 million for the year ended December 31, 2011. As the ABL credit facility was incurred for the benefit of the operations of CVR Refining, all the debt and associated costs have been allocated to CVR Refining. These costs will be deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the facility. In connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately $1.9 million, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.8 million of unamortized deferred financing costs associated with the first priority credit facility will continue to be amortized over the term of the ABL credit facility.

In connection with the closing of CVR Partners’ initial public offering in April 2011, CVR Partners and Coffeyville Resources Nitrogen Fertilizers, LLC (“CRNF”), a wholly-owned subsidiary of CVR Partners, were released as guarantors of the ABL credit facility.

Lease Obligations

As a result of the Wynnewood Acquisition, CVR Refining acquired certain lease assets and assumed related capital lease/financing lease obligations. See Note 4 (“Wynnewood Acquisition”) for further discussion. The underlying assets and related depreciation were included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 214 months remaining through September 2029. In addition, the lease agreement specifics for additional payments related to a throughput deficiency provision. See Note 14 (“Commitments and Contingencies”) for further discussion.

The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 213 months remaining and will expire in September 2029.

 

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Table of Contents
Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Future payments required under capital lease at December 31, 2011 are as follows:

 

     Capital Lease  
     (in thousands)  

2012

   $ 6,239   

2013

     6,269   

2014

     6,312   

2015

     6,355   

2016

     6,412   

2017 and thereafter

     83,199   
  

 

 

 

Total future payments

     114,786   

Less: amount representing interest

     61,567   
  

 

 

 

Present value of future minimum payments

     53,219   

Less: current portion

     960   
  

 

 

 

Long-term portion

   $ 52,259   
  

 

 

 

First Priority Credit Facility

Until April 6, 2010, CRLLC maintained the tranche D term loan totaling approximately $453.3 million. As discussed above, this amount was paid in full with the proceeds of the issuance of the Notes. As of December 31, 2010, the first priority credit facility consisted of a $150.0 million revolving credit facility. As of December 31, 2010, CRLLC had approximately $70.4 million of outstanding letters of credit consisting of approximately $0.2 million in letters of credit in support of certain environmental obligations and approximately $30.6 million in letters of credit to secure transportation services for crude oil and two standby letters of credit totaling approximately $39.7 million issued in support of the purchase of feedstocks. As discussed above the first priority credit facility was terminated on February 22, 2011 and was replaced with an ABL credit facility. As of December 31, 2010, CVR Refining had no borrowings outstanding under the first priority revolving credit facility and had aggregate availability of approximately $79.6 million under the first priority revolving credit facility.

CRLLC’s first priority credit facility contained customary restrictive covenants applicable to CRLLC, including, but not limited to, limitations on the level of additional indebtedness, commodity agreements, capital expenditures, payment of dividends, creation of liens, and sale of assets.

(13) Benefit Plans

CVR Energy sponsors three defined-contribution 401(k) plans (the “Plans”) in which all employees of CVR Refining may participate. Participants in the Plans may elect to contribute up to 50% of their annual salaries, and up to 100% of their annual income sharing. CVR Energy matches up to 75% of the first 6% of the participant’s contribution for the nonunion plan, 75% of the first 6% of the participant’s contribution for the CVR Energy union plan, and 80% on the first 5% of the participant’s contributions plus a 3% employer contribution each pay period for the Wynnewood union plan. All Plans are administered by CVR Energy and contributions for the union plans are determined in accordance with provisions of negotiated labor contracts. Participants in all Plans are immediately vested in their individual contributions. All Plans have a three year vesting schedule for CVR Energy’s matching funds and contain a provision to count service with any predecessor organization. CVR Energy’s contributions under the Plans for employees of CVR Refining were approximately $1.4 million, $1.3 million and $1.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. The Wynnewood Union 401(k) Plan is effective with the Wynnewood Acquisition on December 16, 2011. Participants include all Wynnewood union employees. Wynnewood non-union employees are participants in the CVR Energy 401(k) Plan.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

(14) Commitments and Contingencies

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

 

Year Ending December 31,

   Operating
Leases
     Unconditional
Purchase
Obligations(1)
 
     (in thousands)  

2012

   $ 2,364         96,609   

2013

     1,758         97,534   

2014

     1,169         97,534   

2015

     388         90,026   

2016

     68         83,823   

Thereafter

     211         417,744   
  

 

 

    

 

 

 
   $ 5,958       $ 883,270   
  

 

 

    

 

 

 

 

(1) This amount includes approximately $500.9 million payable ratably over ten years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM will receive transportation for at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

CVR Refining leases various equipment, including real properties under long-term operating leases expiring at various dates. For the years ended December 31, 2011, 2010 and 2009, lease expense totaled approximately $1.4 million, $0.6 million and $41,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR Refining’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.

Additionally, in the normal course of business, CVR Refining has long-term commitments to purchase electricity, storage capacity and pipeline transportation services. See below for further discussion and related expense of material long-term commitments.

CRRM has a Pipeline Construction, Operation and Transportation Commitment Agreement with Plains Pipeline, L.P. (“Plains Pipeline”) pursuant to which Plains Pipeline constructed a crude oil pipeline from Cushing, Oklahoma to Caney, Kansas. The term of the agreement expires on March 1, 2025. Pursuant to the agreement, CRRM has agreed to transport approximately 80,000 barrels per day of its crude oil requirements for the Coffeyville refinery at a fixed charge per barrel for the first five years of the agreement and for the remaining fifteen years of the agreement, CRRM must transport all of its non-gathered crude oil up to the capacity of the pipeline. The rate is subject to a Federal Energy Regulatory Commission (“FERC”) tariff and is subject to change on an annual basis per the agreement. Lease expense associated with this agreement and included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled approximately $9.8 million, $11.4 million and $11.0 million, respectively.

During 2005, CRRM entered into a Pipeage Contract with Mid-American Pipeline Company (“MAPL”) pursuant to which CRRM agreed to ship a minimum quantity of NGLs on an inbound pipeline operated by MAPL between Conway, Kansas and Coffeyville, Kansas. Pursuant to the contract, CRRM is obligated to ship 2 million barrels (“Minimum Commitment”) of NGLs per year at a fixed rate per barrel. All barrels above the Minimum Commitment are at a different fixed rate per barrel. The rates are subject to a tariff approved by the

 

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Kansas Corporation Commission (“KCC”) and are subject to change throughout the term of this contract as ordered by the KCC. In 2011, MAPL filed an application with KCC to increase rates, as discussed in further detail below in the Litigation section. Lease expense associated with this contract agreement and included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled approximately $1.3 million, $2.4 million and $2.4 million, respectively.

During 2004, CRRM entered into a Transportation Services Agreement with CCPS Transportation, LLC (“CCPS”) pursuant to which CCPS reconfigured an existing pipeline (“Spearhead Pipeline”) to transport Canadian sourced crude oil to Cushing, Oklahoma. The agreement expires March 1, 2016. Pursuant to the agreement and pursuant to options for increased capacity which CRRM has exercised, CRRM is obligated to pay an incentive tariff, which is a fixed rate per barrel for a minimum of 10,000 barrels per day. Lease expense associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled approximately $8.4 million, $16.6 million and $9.7 million, respectively.

During 2004, CRRM entered into a Terminalling Agreement with Plains Marketing, LP (“Plains”) whereby CRRM has the exclusive storage rights for working storage, blending, and terminalling services at several Plains tanks in Cushing, Oklahoma. During 2007, CRRM entered into an Amended and Restated Terminalling Agreement with Plains that replaced the 2004 agreement. Pursuant to the Amended and Restated Terminalling Agreement, CRRM is obligated to pay fees on a minimum throughput volume commitment of 29.2 million barrels per year. Fees are subject to change annually based on changes in the Consumer Price Index (“CPI-U”) and the Producer Price Index (“PPI-NG”). Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled approximately $2.4 million, $2.5 million and $2.6 million, respectively. The original term of the Amended and Restated Terminalling Agreement expires December 31, 2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement. Concurrently with the above-described Amended and Restated Terminalling Agreement, CRRM entered into a separate Terminalling Agreement with Plains whereby CRRM has obtained additional exclusive storage rights for working storage and terminalling services at several Plains tanks in Cushing, Oklahoma. CRRM is obligated to pay Plains fees based on the storage capacity of the tanks involved, and such fees are subject to change annually based on changes in the Producer Price Index (“PPI-FG” and “PPI-NG”). Expenses associated with this Terminalling Agreement totaled approximately $3.3 million, $3.1 million and $3.5 million for 2011, 2010 and 2009, respectively. Select tanks covered by this agreement have been designated as delivery points for crude oil.

During 2006, CRRM entered into a Lease Storage Agreement with Enterprise Crude Pipeline LLC (“Enterprise”) (as successor in interest to TEPPCO Crude Pipeline, L.P.) whereby CRRM leases tank capacity at Enterprise’s Cushing tank farm in Cushing, Oklahoma. In September 2006, CRRM exercised its option to increase the shell capacity leased at the facility subject to this agreement. Pursuant to the agreement, CRRM is obligated to pay a monthly per barrel fee regardless of the number of barrels of crude oil actually stored at the leased facilities. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled approximately $1.8 million, $1.3 million and $1.3 million, respectively. CRRM and Enterprise entered into a new five-year lease agreement for the above-described tank capacity effective March 1, 2011.

On October 10, 2008, CRRM entered into ten year agreements with Magellan Pipeline Company LP (“Magellan”) that will allow for the transportation of an additional 20,000 barrels per day of refined fuels from CVR Refining’s Coffeyville, Kansas refinery and the storage of refined fuels on the Magellan system. CRRM commenced usage of the capacity lease in December 2009 and the storage of refined fuels commenced in April

 

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2010. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010 and 2009, totaled $0.7 million, $0.6 million and $60,000, respectively.

On December 15, 2011, CVR Refining consummated the Wynnewood Acquisition, which resulted in the assumption of certain agreements. CVR Refining assumed a throughput and deficiency agreement with Excel Pipeline LLC that expires in 2020. Under the agreement, CVR Refining is obligated to pay a tariff fee on the minimum daily volume of crude oil or else pay for any deficiencies. Expenses associated with the throughput and deficiency agreement are estimated to be approximately $4.0 million per year.

Litigation

From time to time, CVR Refining is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Management believes the Partnership has accrued for losses for which it may ultimately be responsible. It is possible that management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying combined financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, “Samson”) filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs filed two lawsuits (the “Anstine and Arrow cases”) against CRRM and other defendants in state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remained in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the SemGroup bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, “Sem”), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased by Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company (“J. Aron”) and that J. Aron sold some of this crude oil to CRRM. The Samson lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of the plaintiffs’ alleged claims is unknown since the price and amount of crude oil sold by the plaintiffs and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron. The claims in the Anstine and Arrow cases seek an accounting and payment from CRRM for crude oil that CRRM purchased directly from the Anstine and Arrow plaintiffs. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, agreed to defend CRRM in connection with any direct purchases of crude oil from Sem and agreed to reimburse CRRM’s prior attorney fees and out-of-pocket expenses in connection with the lawsuits. Samson and CRRM have entered a stipulation of dismissal with respect to all of the Samson cases and the Samson cases were dismissed with prejudice on February 8, 2012. The dismissal does not pertain to the Anstine and Arrow cases.

 

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On July 25, 2011, Mid-America Pipeline Company, LLC (“MAPL”) filed an application with the Kansas Corporation Commission (“KCC”) for the purpose of establishing rates (“New Rates”) effective October 1, 2011 for pipeline transportation service on MAPL’s liquids pipelines running between Conway, Kansas and Coffeyville, Kansas (“Inbound Line”) and between Coffeyville, Kansas and El Dorado, Kansas (“Outbound Line”). CRRM currently ships refined fuels on the Outbound Line pursuant to transportation rates established by a pipeline capacity lease with MAPL which expired September 30, 2011 and CRRM currently ships natural gas liquids on the Inbound Line pursuant to a pipeage contract which also expired September 30, 2011. If MAPL were successful in obtaining the entirety of its proposed rate increase, under CRRM’s historic pipeline usage patterns, the New Rates would result in a total annual increase of approximately $14.75 million for CRRM’s use of the Inbound and the Outbound Lines. On September 30, 2011, the KCC issued an order continuing, on an interim basis, the existing rates for the Inbound Line and the Outbound Line from October 1, 2011 until the resolution of the matter. In addition, on September 21, 2011, MAPL filed an application with the U. S. Federal Energy Regulatory Commission (“FERC”) for a rate increase on the Outbound Line with respect to shipments with an interstate destination. On October 28, 2011 FERC issued an order allowing MAPL to place its increased rate into effect October 1, 2011 with respect to interstate shipments, subject to refund based on the final outcome of the FERC proceedings. Historically, the majority of CRRM’s shipments on the Outbound Line are to Kansas intrastate destinations and therefore, are subject to KCC and not FERC rate regulation. On April 3, 2012, the parties entered into a Settlement Agreement which resolved the rate dispute both at the KCC and at FERC. Among other provisions, the Settlement Agreement provides for pipeage contracts to be entered into between the parties with rates (“Settlement Rates”) to be established for an initial one year period. The Settlement Rates consist of two components, a base rate and a pipeline integrity cost recovery rate along with an annual take or pay minimum transportation quantity. The Settlement Rate on the Inbound Line was effective April 1, 2012 and the Settlement Rate on the Outbound Line was effective June 1, 2012. Prior to the end of the initial one year term of the pipeage contracts, and prior to the end of each annual period thereafter until the tenth anniversary of each of the two pipeage contracts, MAPL will provide its estimate of pipeline integrity costs for the upcoming annual period and CRRM may either agree to pay a rate for such upcoming annual period which includes a recovery rate component sufficient to collect such pipeline integrity costs for such upcoming annual period subject to true-up to actual costs at the end of the annual period. FERC rates will be the same as the KCC rates.

Flood, Crude Oil Discharge and Insurance

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

As a result of the crude oil discharge that occurred on July 1, 2007, CVR Refining entered into an administrative order on consent (the “Consent Order”) with the U. S. Environmental Protection Agency (“EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from CVR

 

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Refining’s Coffeyville refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, CVR Refining agreed to perform specified remedial actions to respond to the discharge of crude oil from CVR Refining’s refinery. The substantial majority of all required remedial actions were completed by January 31, 2009. CVR Refining prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided CVR Refining with a notice of completion indicating that CVR Refining has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties.

On October 25, 2010, CVR Refining received a letter from the United States Coast Guard on behalf of the EPA seeking approximately $1.8 million in oversight cost reimbursement. CVR Refining responded by asserting defenses to the Coast Guard’s claim for oversight costs. On September 23, 2011, the United States Department of Justice (“DOJ”), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking (i) recovery from CRRM of the EPA’s oversight costs, (ii) a civil penalty under the Clean Water Act (as amended by the OPA) and (iii) recovery from CRRM related to alleged non-compliance with the Clean Air Act’s Risk Management Program (“RMP”). (See “Environmental, Health and Safety (“EHS”) Matters” below.) The Company has reached an agreement with DOJ to resolve DOJ’s claims. Civil penalties associated with the proceeding will exceed $100,000; however, the Company does not anticipate that civil penalties or any other costs associated with the settlement will be material. The lawsuit is temporarily stayed while the parties finalize and file the consent decree.

CVR Refining is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, CRRM filed a lawsuit in the United States District Court for the District of Kansas against certain of its environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, CVR Refining cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the claims. CVR Refining has received $25 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment of the primary pollution liability policy limit.

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

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

CRRM, CRCT, CRT and WRC are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.

CRRM, CRCT, WRC and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution. Therefore, CRRM, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property

 

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where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States.

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under the RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of December 31, 2011 and 2010, environmental accruals of approximately $1.9 million and $4.1 million, respectively, were reflected in the combined Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.5 million and $1.5 million, respectively, are included in other current liabilities. CVR Refining’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at December 31, 2011 and 2010, respectively. The accruals include estimated closure and post-closure costs of approximately $0.9 million and $0.9 million for two landfills at December 31, 2011 and 2010, respectively. The estimated future payments for these required obligations are as follows:

 

Year Ending December 31,

   Amount  
     (in thousands)  

2012

   $ 464   

2013

     166   

2014

     166   

2015

     166   

2016

     109   

Thereafter

     1,077   
  

 

 

 

Undiscounted total

     2,148   

Less amounts representing interest at 1.69%

     225   
  

 

 

 

Accrued environmental liabilities at December 31, 2011

   $ 1,923   
  

 

 

 

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

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

 

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In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. With the change in control by Icahn Enterprises in 2012 (See Note 19 “Subsequent Events”), the MSAT II projects have been accelerated by three months due to the loss of small refiner status. Capital expenditures to comply with the rule are expected to be approximately $59 million for CRRM and $78 million for WRC.

CRRM’s refinery is subject to the Renewable Fuel Standard (“RFS”) which requires refiners to blend “renewable fuels” in with their transportation fuels or purchase renewable energy credits in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. In 2012, about 9% of all fuel used was required to be “renewable fuel.” The EPA has not yet proposed the renewable fuel percentage standards for 2013. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U. S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. For the year ended December 31, 2011, CRRM incurred approximately $19.0 million of expense associated with the purchasing RINs which was included in cost of product sold in the combined Statements of Operations. To achieve compliance with the renewable fuel standard for the remainder of 2012, CRRM is able to blend a small amount of ethanol into gasoline sold at its refinery loading rack, but otherwise will have to purchase RINs to comply with the rule. CRRM requested “hardship relief” (an extension of the compliance deadline) from the EPA based on the disproportionate economic impact of the rule on CRRM, but the EPA denied CRRM’s request on February 17, 2012.

WRC’s refinery is a small refinery under the RFS and has received a two year extension of time to comply. Therefore, WRC will have to begin complying with the RFS beginning in 2013 unless a further extension is requested and granted.

The EPA is expected to propose “Tier 3” gasoline sulfur standards in 2012 or 2013. If the EPA were to propose a standard at the level recently being discussed in the pre-proposal phase by the EPA, CRRM will need to make modifications to its equipment in order to meet the anticipated new standard. It is not anticipated that the Wynnewood refinery would require additional capital to meet the anticipated new standard. The Partnership does not believe that costs associated with the EPA’s proposed Tier 3 rule will be material.

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

In March 2012, CRRM entered into a “Second Consent Decree” with the EPA, which replaces the 2004 Consent Decree (other than the cleanup obligations) and the First Material Modification. The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a “global settlement” under the EPA’s “National Petroleum

 

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Refining Initiative.” Under the National Petroleum Refining Initiative, the EPA identified industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Partnership was required to pay a civil penalty of approximately $0.7 million and is required complete the installation of FCCU controls required under the 2004 Consent Decree, the remaining costs of which are expected to be approximately $49.0 million, of which approximately $47.0 million is expected to be capital expenditures and complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. The incremental capital expenditures associated with the Second Consent Decree would not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by U.S. District Court for the District of Kansas on April 19, 2012.

WRC’s refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the “ODEQ”) under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the “Wynnewood Consent Order”). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The costs of complying with the Wynnewood Consent Order, other than costs associated with a planned turnaround, are expected to be approximately $1.5 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ Order. The EPA may later request that WRC enter into a global settlement which, if WRC agreed to do so, would necessitate the payment of a civil penalty and the installation of additional controls.

On February 24, 2010, CRRM received a letter from the DOJ on behalf of the EPA seeking an approximately $0.9 million civil penalty related to alleged late and incomplete reporting of air releases in violation of the CERCLA and the Emergency Planning and Community Right-to-Know Act (“EPCRA”). CVR Refining has reached an agreement with EPA to resolve these claims. The resolution was included in the Second Consent Decree described above, pursuant to which the Partnership has agreed to pay an immaterial civil penalty.

The EPA has investigated CRRM’s operation for compliance with the RMP. On September 23, 2011, the DOJ, acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas (in addition to the matters described above, see “Flood, Crude Oil Discharge and Insurance”) seeking recovery from CRRM related to alleged non-compliance with the RMP. The Partnership has reached an agreement to settle the claims. Civil penalties associated with the proceeding will exceed $100,000; however, the Partnership does not anticipate that civil penalties or any other costs associated with the settlement will be material. The lawsuit is temporarily stayed while the parties attempt to finalize and file the consent decree.

WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the “CWA Consent Order”), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged noncompliance by WRC with its Oklahoma Pollutant Discharge Elimination System permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery’s wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational

 

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changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, we do not believe that the costs of the potential corrective actions would be material.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31, 2011, 2010 and 2009, capital expenditures were approximately $7.4 million, $13.0 million and $23.5 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

CRRM, CRCT, WRC and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.

(15) Fair Value Measurements

In September 2006, the FASB issued ASC Topic 820 – Fair Value Measurements and Disclosures (“ASC 820”). ASC 820 established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

 

   

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

 

   

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

 

   

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

 

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The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 2011 and 2010.

 

     December 31, 2011  
     Level 1      Level 2      Level 3      Total  
     (in thousands)  

Location and Description

           

Cash equivalents

   $ 2,745       $ —         $ —         $ 2,745   

Other current assets (other derivative agreements)

     —           63,051         —           63,051   

Other long-term assets (other derivative agreements)

     —           18,831         —           18,831   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets

   $ 2,745       $ 81,882       $ —         $ 84,627   
  

 

 

    

 

 

    

 

 

    

 

 

 

Other current liabilities (other derivative agreements)

     —           —           —           —     

Other long-term assets (other derivative agreements)

     —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Liabilities

   $ —         $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     December 31, 2010  
     Level 1      Level 2     Level 3      Total  
     (in thousands)  

Location and Description

  

Cash equivalents

   $ 2,327       $ —        $ —         $ 2,327   
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Assets

   $ 2,327       $ —        $ —         $ 2,327   
  

 

 

    

 

 

   

 

 

    

 

 

 

Other current liabilities (Other derivative agreements)

   $ —         $ (4,043   $ —         $ (4,043
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Liabilities

   $ —         $ (4,043   $ —         $ (4,043
  

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining’s cash equivalents and derivative instruments. Additionally, the fair value of the Notes is disclosed in Note 12 (“Long-Term Debt”). The commodity derivative contracts are valued using broker quoted market prices of similar commodity contracts using level 2 inputs. CVR Refining had no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2011.

(16) Derivative Financial Instruments

Gain (loss) on derivatives, net consisted of the following:

 

     Year Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Realized loss on swap agreements

   $ —        $ —        $ (14,331

Unrealized loss on swap agreements

     —          —          (40,903

Realized loss on other derivative agreements

     (7,182     (2,140     (13,164

Unrealized gain on other derivative agreements

     85,262        634        3,112   
  

 

 

   

 

 

   

 

 

 

Total gain (loss) on derivatives, net

   $ 78,080      $ (1,506   $ (65,286
  

 

 

   

 

 

   

 

 

 

CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix

 

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NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

margins on certain future production, CVR Refining from time to time enters into various commodity derivative transactions. CVR Refining entered into certain commodity derivate contracts and, through CRLLC, entered into an interest rate swap as required by the long-term debt agreements. The commodity derivative contracts are for the purpose of managing price risk on crude oil and finished goods and the interest rate swap was for the purpose of managing interest rate risk until June 30, 2010.

CVR Refining has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR Refining holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the combined Statements of Operations.

CVR Refining maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the combined Balance Sheets. The maintenance margin balance is included within other current assets within the combined Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the combined Balance Sheets. From time to time, CVR Refining may be required to deposit additional funds into this margin account.

Commodity Swap

Beginning September 2011, CRLLC, for the benefit of CRRM, entered into several commodity swap contracts with effective periods beginning in January 2012. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the combined Balance Sheets with changes in fair value currently recognized in the combined Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2011, CVR Refining had open commodity hedging instruments consisting of 13 million barrels of crack spreads, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at December 31, 2011 was a net unrealized gain of $80.4 million. In addition, the combined financial statements include a commodity swap assumed as part of its Wynnewood Acquisition that expired on December 31, 2011. This commodity swap was not designated as a hedge.

Cash Flow Swap

Until October 8, 2009, CRLLC had been a party to commodity derivative contracts (referred to as the “Cash Flow Swap”) that were originally executed on June 16, 2005. The swap agreements were executed at the prevailing market rate at the time of execution and were to provide an economic hedge on future transactions. The Cash Flow Swap resulted in unrealized gains (losses), using a valuation method that utilized quoted market prices. On October 8, 2009, CRLLC and J. Aron, the swap counterparty and a related party, agreed to terminate the Cash Flow Swap. The Cash Flow Swap was originally scheduled to terminate in 2010; however, an amendment to CRLLC’s credit facility completed on October 2, 2009, permitted early termination. As a result of the early termination, a settlement totaling approximately $3.9 million was paid to CRLLC, for the benefit of CRRM, by J. Aron. See Note 17 (“Related Party Transactions”) for further discussion of the Cash Flow Swap.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Interest Rate Swap

Until June 30, 2010, CRLLC, on behalf of the Refining Subsidiaries, held derivative contracts known as interest rate swap agreements (the “Interest Rate Swap”) that converted floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180.0 million from March 31, 2009 until March 31, 2010 and $110.0 million from March 31, 2010 until June 30, 2010. The Interest Rate Swap expired on June 30, 2010. Half of the Interest Rate Swap agreements were held with a related party (as described in Note 17, “Related Party Transactions”), and the other half were held with a financial institution that was also a lender under CRLLC’s first priority credit facility until April 6, 2010.

Under the Interest Rate Swap, CRLLC paid the fixed rate of 4.195% and received a floating rate based on three month LIBOR rates, with payments calculated on the notional amount. The notional amount did not represent the actual amount exchanged by the parties but instead represented the amount on which the contracts are based. The Interest Rate Swap was settled quarterly and marked to market at each reporting date with all unrealized gains and losses recognized in income.

(17) Related Party Transactions

In connection with the formation of CVR Refining in September 2012, CVR Refining and CRRM will enter into a services agreement with CVR Energy and its subsidiaries that governs the business relations among CVR Refining, its general partner and CRRM on the one hand, and CVR Energy and its subsidiaries, on the other hand. CRRM has previously entered into other agreements with CVR Partners and its subsidiary. Certain of the agreements described below were amended and restated on April 13, 2011 in connection with the initial public offering of CVR Partners; the agreements are described as in effect at December 31, 2011. Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable, prepaid expenses and other current assets, and other long-term assets, on the combined Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CVR Refining and CRRM with respect to these agreements are included in accounts payable, accrued expenses and other current liabilities, and other long-term liabilities, on CVR Refining’s combined Balance Sheets.

Feedstock and Shared Services Agreement

CRRM entered into a feedstock and shared services agreement with CRNF under which the two parties provide feedstock and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM’s Coffeyville, Kansas refinery and CRNF’s nitrogen fertilizer plant.

Pursuant to the feedstock agreement, CRRM and CRNF have the obligation to transfer excess hydrogen to one another. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining. Net monthly receipts of hydrogen from CRNF have been reflected in cost of product sold (exclusive of depreciation and amortization) for CVR Refining. For the years ended December 31, 2011, 2010 and 2009, the net sales generated from the sale of hydrogen to CRNF were approximately $1.0 million, $1.8 million and $1.6 million, respectively. For the years ended December 31, 2011, 2010 and 2009, CVR Refining also recognized $14.2 million, $0.1 million and $0.8 million of cost of product sold (exclusive of depreciation and amortization) related to the purchase of excess hydrogen from the nitrogen fertilizer facility, respectively. At December 31, 2011 and 2010, there was approximately $0.1 million and $0.3 million, respectively, of payables included in accounts payable on the combined Balance Sheets associated with unpaid balances related to hydrogen.

The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net reimbursed or (paid) direct operating expenses recorded during the years ended December 31,

 

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CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

2011, 2010 and 2009 were approximately $0.2 million, $0.1 million and $(0.2) million, respectively, related to high-pressure steam. Reimbursements or paid amounts for each of the years on a gross basis were nominal.

CRNF is also obligated to make available to CRRM any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by CRNF in a commercially reasonable manner. Direct operating expenses associated with nitrogen purchased by CRRM from CRNF for the years ended December 31, 2011, 2010 and 2009, were approximately $1.5 million, $0.8 million and $0.8 million, respectively. No amounts were paid by CRNF to CRRM for any of the years.

The agreement also provides a mechanism pursuant to which CRNF transfers a tail gas stream to CRRM. For the year ended December 31, 2011, CRRM recognized approximately $0.2 million of direct operating expenses generated from the purchase of tail gas from CRNF.

In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF has agreed to pay CRRM the cost of installing the pipe over the next three years and in the fourth year provide an additional 15% to cover the cost of capital. At December 31, 2011, an asset of approximately $0.5 million was included in other current assets and approximately $0.8 million was included in other non-current assets with an offset liability of approximately $0.2 million in other current liabilities and approximately $1.5 million other non-current liabilities in the combined Balance Sheet.

CRNF also provided finished product tank capacity to CRRM under the agreement. Approximately $0.3 million was incurred by CRRM for the use of tank capacity for the year ended December 31, 2011. This expense was recorded as direct operating expenses. No amounts were paid in prior years.

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

At December 31, 2011 and 2010, payables of $0.3 million and $0.3 million, respectively, were included in accounts payable on the combined Balance Sheets associated for amounts yet to be paid related to components of the feedstock and shared services agreement. At December 31, 2011 and 2010, receivables of $0.3 million and $0.8 million, respectively, were included in prepaid expenses and other current assets on the combined Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.

Coke Supply Agreement

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

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

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

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

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

Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $11.4 million, $4.3 million and $6.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. Receivables of $1.0 million and $0.1 million related to the coke supply agreement were included in accounts receivable on the combined Balance Sheets at December 31, 2011, and 2010, respectively.

Lease Agreement

CRRM entered into a lease agreement with CRNF under which CRNF leases certain office and laboratory space. The initial term of the lease will expire in October 2017, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, CRNF has the option to renew the lease agreement for up to five additional one-year periods by providing CRRM with notice of renewal at least 60 days prior to the expiration of the then existing term. For the years ended December 31, 2011, 2010 and 2009, amounts received related to the use of the office and laboratory space totalled approximately $0.1 million for all years. There were no receivables outstanding with respect to the lease agreement as of December 31, 2011 and 2010, respectively.

Environmental Agreement

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

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

 

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CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

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

Cash Flow Swap

CRLLC, on behalf of CRRM, entered into a Cash Flow Swap with J. Aron, a subsidiary of GS Capital Partners V, L.P. and related entities (“GS”). These agreements were entered into on June 16, 2005, with an expiration date of June 30, 2010. As described in Note 16 (“Derivative Financial Instruments”), the Cash Flow Swap was terminated by the parties effective October 8, 2009. The termination resulted in a settlement payment from J. Aron totaling approximately $3.9 million. Amounts totaling approximately $(55.2) million were reflected in loss on derivatives, net, related to these swap agreements for the year ended December 31, 2009.

J. Aron Deferrals

As a result of the June/July 2007 flood and the related temporary cessation of business operations, CRLLC, on behalf of CRRM, entered into deferral agreements for amounts owed to J. Aron under the Cash Flow Swap discussed above. The amount deferred, excluding accrued interest, totaled approximately $123.7 million. Of the deferred balances, approximately $61.3 million had been repaid as of December 31, 2008 and the remaining deferral obligation of approximately $62.4 million, including accrued interest of approximately $0.5 million, was paid in the first quarter of 2009. Interest relating to the deferred payment agreements is reflected in interest expense and other financing costs. As the obligation was settled in 2009, there was no financial statement impact for the years ended December 31, 2010 and 2011. For the year ended December 31, 2009, interest expense associated with the deferral agreement totaled approximately $0.3 million.

Interest Rate Swap

On June 30, 2005, CRLLC entered into three Interest Rate Swap agreements with J. Aron for the benefit of CRRM. Amounts totaling $(16,000) and approximately $(0.8) million are recognized in gain (loss) on derivatives, net, related to these swap agreements for the years ended December 31, 2010 and 2009, respectively. The Interest Rate Swap expired June 30, 2010.

Financing and Other

In March 2010, CRLLC amended its outstanding first priority credit facility, which was incurred for the benefit of the Refining Subsidiaries. See Note 12 (“Long-Term Debt”) for further discussion. In connection with the amendment, CVR Refining paid a subsidiary of GS fees and expenses of approximately $0.9 million for their services as lead bookrunner. In addition, on April 6, 2010, a subsidiary of GS received a fee of $2.0 million as a participating underwriter upon completion of the issuance of the Notes (as described in Note 13 “Long-Term Debt”).

For the years ended December 31, 2011 and 2010, CVR Refining recognized approximately $0.5 million and $0.7 million, respectively, in expenses for the benefit of GS, Kelso Investment Associates VII, L.P. and related entities, and the president, chief executive officer and chairman of the Board of CVR Energy, in connection with CVR Energy’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees.

CVR Refining recognized approximately $0.5 million for the year ended December 31, 2009 in registration expenses relating to the secondary offering that occurred in 2009 for the benefit of GS in connection with CVR Energy’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees, and external legal fees.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

In October 2009, CRLLC amended the outstanding first priority credit facility. See Note 12 (“Long-Term Debt”) for further discussion. In connection with the amendment, as reflected in these combined Financial Statements, CRLLC paid a subsidiary of GS a fee of $0.9 million for their services as lead bookrunner. Additionally, CRLLC paid a lender fee of approximately $7,000 in conjunction with this amendment to a different subsidiary of GS. The affiliate was one of the many lenders under the first priority credit facility.

(18) Major Customers and Suppliers

Sales to major customers were as follows:

 

     Year Ended
December 31,
 
     2011     2010     2009  

Customer A

     15     14     14

Customer B

     12     11     10

Customer C

     9     10     11
  

 

 

   

 

 

   

 

 

 
     36     35     35
  

 

 

   

 

 

   

 

 

 

In connection with an agreement entered into on December 31, 2008, CRRM obtained crude oil from one supplier for 2009, 2010 and 2011. Purchases contracted as a percentage of the total cost of product sold (exclusive of depreciation and amortization) for each of the periods were as follows:

 

     Year Ended
December 31,
 
     2011     2010     2009  

Supplier A

     65     64     69
  

 

 

   

 

 

   

 

 

 

(19) Subsequent Events

CVR Refining evaluated subsequent events, if any, that would require an adjustment to CVR Refining’s combined financial statements or require disclosure in the notes to the combined financial statements through the date of issuance of the combined financial statements.

Icahn Acquisition

On April 18, 2012, IEP Energy LLC (“IEP Energy”), a majority owned subsidiary of Icahn Enterprises, L.P. (“Icahn Enterprises”), and certain other affiliates of Icahn Enterprises and Carl C. Icahn (collectively, the “IEP Parties”), entered into a Transaction Agreement (the “Transaction Agreement”) with CVR Energy, with respect to IEP Energy’s tender offer (the “Offer”) to purchase all of the issued and outstanding shares of CVR Energy’s common stock for a price of $30 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent payment right for each share of CVR Energy common stock (the “CCP”), which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or prior to August 18, 2013 and such transaction closes.

On May 7, 2012, the IEP Parties announced that a majority of the common stock of CVR Energy had been acquired through the Offer. As a result of the shares tendered into the Offer during the initial offering period, the subsequent offering period and subsequent additional purchases, the IEP parties owned approximately 82% of CVR Energy’s common stock as of September 2012.

 

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Index to Financial Statements

CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

Pursuant to the Transaction Agreement, all employee restricted stock awards (“awards”) that vest in 2012 will vest in accordance with the current vesting terms and upon vesting will receive the offer price of $30 per share in cash plus one CCP. For all such awards that vest in accordance with their terms in 2013, 2014 and 2015, the holders of the awards will receive the lesser of the offer price or the appraised value of the shares at the time of vesting. As a result of the modification, additional share-based compensation was incurred at CVR Energy to revalue the unvested shares to the fair value upon the date of modification. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

The change of control required the Issuers of the Notes to make an offer to repurchase all of the Notes. On June 4, 2012, the Issuers offered to purchase all or any part of the Notes, at a cash purchase price of 101% of the aggregate principal amount of the Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Notes tendered.

In connection with the change in control of CVR Energy, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the “ABL First Amendment”), pursuant to which the parties agreed to exclude Icahn’s acquisition of the common shares of CVR Energy from the definition of change of control as provided in the ABL credit facility. Absent the ABL First Amendment, the change in control of CVR Energy would have triggered an event of default pursuant to the ABL credit facility.

Icahn Sourcing

Icahn Sourcing, LLC (“Icahn Sourcing”) is an entity formed and controlled by Carl C. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property. CVR Refining is a member of the buying group and, as such, is afforded the opportunity to purchase goods, services and property from vendors with whom Icahn Sourcing has negotiated rates and terms. Icahn Sourcing does not guarantee that CVR Refining will purchase any goods, services or property from any such vendors and CVR Refining is under no obligation to do so. CVR Refining does not pay Icahn Sourcing any fees or other amounts with respect to the buying group arrangement. CVR Refining has purchased a variety of goods and services as members of the buying group at prices and on terms that management believes are more favorable than those which would be achieved on a stand-alone basis.

New Vitol Agreement

On August 31, 2012, CRRM and Vitol Inc. (“Vitol”), entered into an Amended and Restated Crude Oil Supply Agreement (the “Vitol Agreement”). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended (the “Previous Supply Agreement”). The terms of the Vitol Agreement provide that CRRM will obtain all of the crude oil for the Company’s two oil refineries through Vitol, other than crude oil that CRRM acquires in Kansas, Missouri, North Dakota, Oklahoma, Texas, Wyoming and all states adjacent to such states and crude oil that is transported in whole or in part via railcar or truck. Pursuant to the Vitol Agreement, CRRM and Vitol work together to identify crude oil and pricing terms that meet CRRM’s crude oil requirements. CRRM and/or Vitol negotiate the cost of each barrel of crude oil that is purchased from third party crude oil suppliers. Vitol purchases all such crude oil, executes all third party sourcing transactions and provides transportation and other logistical services for the subject crude oil. Vitol then sells such crude oil and delivers the same to CRRM. Title and risk of loss for all crude oil purchased by CRRM via the Vitol Agreement passes to CRRM upon delivery to one of the Company’s delivery points designated in the Vitol Agreement. CRRM pays Vitol a fixed origination fee per barrel plus the negotiated cost

 

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CVR Refining, LP

NOTES TO COMBINED FINANCIAL STATEMENTS (continued)

 

(including logistics costs) of each barrel of crude oil purchased. The Vitol Agreement has an initial term commencing August 31, 2012 and extending through December 31, 2014 (the “Initial Term”). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a “Renewal Term”) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of the Initial Term or any Renewal Term. Notwithstanding the foregoing, CRRM has an option to terminate the Vitol Agreement effective December 31, 2013 by providing written notice of termination to Vitol on or before May 1, 2013.

 

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Index to Financial Statements

GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2011 AND DECEMBER 31, 2010

(Unaudited)

 

    2011     2010  

ASSETS

   

CURRENT ASSETS:

   

Cash and cash equivalents

  $ 28,956,508      $ 34,045,795   

Restricted cash

    124,782        124,101   

Investments

    322,480        372,786   

Accounts receivable:

   

Trade—net of allowances of $839,183 and $203,964 in 2011 and 2010, respectively

    137,287,860        63,732,241   

Affiliates

    197,815        174,543   

Note receivable—related-party

    56,900        894   

Inventories

    177,212,978        169,756,197   

Prepaid expenses and other

    8,909,952        4,001,060   
 

 

 

   

 

 

 

Total current assets

    353,069,275        272,207,617   
 

 

 

   

 

 

 

PROPERTY, PLANT, AND EQUIPMENT—Net

    280,353,633        279,236,570   

DEFERRED TURNAROUND COSTS—Net

    14,208,158        24,044,574   

INTANGIBLE ASSETS—Net

    1,090,146        1,139,906   

OTHER ASSETS—Net

    3,495,150        9,910,006   
 

 

 

   

 

 

 

TOTAL ASSETS

  $ 652,216,362      $ 586,538,673   
 

 

 

   

 

 

 

LIABILITIES AND SHAREHOLDER’S EQUITY

   

CURRENT LIABILITIES:

   

Accounts payable

  $ 197,723,074      $ 215,522,352   

Accrued liabilities and other

    19,050,059        18,285,313   

Derivative liabilities

    7,435,210        —     

Tax dividend obligation to parent

    30,371,000        —     

Long-term debt—current portion—net of discount

    46,401,137        14,582,463   
 

 

 

   

 

 

 

Total current liabilities

    300,980,480        248,390,128   
 

 

 

   

 

 

 

NONCURRENT LIABILITIES:

   

Long-term debt—net of discount

    53,823,116        129,676,133   

Other

    38,429        76,859   
 

 

 

   

 

 

 

Total noncurrent liabilities

    53,861,545        129,752,992   
 

 

 

   

 

 

 

Total liabilities

    354,842,025        378,143,120   
 

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 8)

   

SHAREHOLDER’S EQUITY:

   

Common stock, $0.01 par value; authorized 150,000 voting shares; issued and outstanding 96,900 shares

   

Authorized 150,000 nonvoting shares; none issued

    969        969   

Contributed capital

    36,357,640        36,357,640   

Retained earnings

    261,015,641        172,034,444   

Accumulated other comprehensive income (loss)

    87        2,500   
 

 

 

   

 

 

 

Total shareholder’s equity

    297,374,337        208,395,553   
 

 

 

   

 

 

 

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY

  $ 652,216,362      $ 586,538,673   
 

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

 

     2011     2010  

OPERATING REVENUE

   $ 2,041,263,810      $ 1,541,973,414   

OPERATING EXPENSES

     1,857,185,583        1,512,229,444   
  

 

 

   

 

 

 

GROSS PROFIT

     184,078,227        29,743,970   

GENERAL AND ADMINISTRATIVE EXPENSES

     13,903,449        12,055,151   
  

 

 

   

 

 

 

OPERATING INCOME

     170,174,778        17,688,819   
  

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

    

Interest and investment income

     88,990        29,508   

Interest expense

     (22,900,258     (16,647,608

Gain on disposal of assets

     176,201        12,052   

Other income (expense)—net

     (289,514     726,651   
  

 

 

   

 

 

 

Total other expense

     (22,924,581     (15,879,397
  

 

 

   

 

 

 

NET INCOME

   $ 147,250,197      $ 1,809,422   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

CONSOLIDATED STATEMENTS OF CHANGES IN RETAINED EARNINGS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

 

     2011     2010  

BALANCE AT JANUARY 1,

   $ 172,034,444      $ 155,889,012   

NET INCOME

     147,250,197        1,809,422   

TAX DIVIDENDS DECLARED

     (58,269,000     —     
  

 

 

   

 

 

 

BALANCE AT SEPTEMBER 30,

   $ 261,015,641      $ 157,698,434   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

 

     2011     2010  

NET INCOME

   $ 147,250,197      $ 1,809,422   

UNREALIZED LOSS ON INVESTMENTS

     (2,413     (3,356
  

 

 

   

 

 

 

COMPREHENSIVE INCOME

   $ 147,247,784      $ 1,806,066   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Unaudited)

 

    2011     2010  

CASH FLOWS FROM OPERATING ACTIVITIES:

   

Net income

  $ 147,250,197      $ 1,809,422   

Adjustments to reconcile net income from continuing operations to net cash used in operating activities:

   

Depreciation and amortization

    13,132,852        10,629,882   

Amortization of turnaround costs

    9,836,416        10,466,956   

Amortization of deferred debt issuance costs and discount on debt

    9,059,837        5,827,696   

Gain on sale of assets

    (176,201     (12,052

Realized gain on sale of investments—net

    (11,152     (4,529

Provision for losses on accounts receivable

    839,183        —     

Unrealized loss on derivative instrument

    37,853,684        —     

Changes in operating assets and liabilities:

   

Increase in accounts receivable—net

    (74,394,802     (24,655,742

Increase in accounts receivable—affiliate

    (23,272     (34,951

(Increase) decrease in inventories

    (7,456,781     2,345,728   

Increase in prepaid expenses and other

    (2,530,038     (1,433,640

Decrease in accounts payable

    (18,340,168     (15,659

Increase (decrease) in accrued liabilities

    751,440        (2,179,442

Decrease in derivative liabilities

    (30,418,474     —     

Decrease in other liabilities

    (25,124     (18,736
 

 

 

   

 

 

 

Net cash provided by operating activities

    85,347,597        2,724,933   
 

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

   

Capital expenditures—refinery

    (13,975,292     (36,453,656

Proceeds from sale of assets—net

    492,229        13,652   

Proceeds from property insurance

    —          117,984   

Purchase of investments

    (1,494     (321,034

Proceeds from sale of investments—net

    60,539        320,023   

Change in restricted cash

    (681     308,080   

Note receivable—related-party

    (56,900     —     

Note receivable—related-party collection

    894        2,298   
 

 

 

   

 

 

 

Net cash used in investing activities

    (13,480,705     (36,012,653
 

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

   

Borrowings under long-term debt

  $ 315,100,000      $ 724,788,766   

Principal payments on long-term debt

    (362,404,194     (693,465,195

Borrowings under notes payable to parent

    89,000,000        31,100,000   

Principal payments on notes payable to parent

    (89,000,000     (31,100,000

Capital lease obligation payments

    (346,708     (317,365

Payments of debt issuance costs

    (1,407,277     (2,903,539

Tax dividend obligation distributed

    (27,898,000     —     
 

 

 

   

 

 

 

Net cash (used in) provided by financing activities

    (76,956,179     28,102,667   
 

 

 

   

 

 

 

Net decrease in cash and cash equivalents

    (5,089,287     (5,185,053

CASH AND CASH EQUIVALENTS—Beginning of year

    34,045,795        5,971,551   
 

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS—End of period

  $ 28,956,508      $ 786,498   
 

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

   

Cash paid during the year for interest and financing expenses—net of amounts capitalized

  $ 15,580,293      $ 14,408,147   
 

 

 

   

 

 

 

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

   
   

Additions to construction projects in progress funded through accounts payable

  $ 1,265,077      $ 3,515,073   
 

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. BACKGROUND AND ORGANIZATION

Gary-Williams Energy Corporation (“GWEC”) is incorporated in Delaware. GWEC became a wholly owned subsidiary of GWEC Holding Company, Inc. (the “Holding Company”) on October 30, 2009 when The Gary-Williams Company (“TGWC”), its then parent company, contributed all of its common shares of GWEC to the Holding Company and canceled its outstanding preferred stock. GWEC’s primary activities are purchasing refinery feedstocks, marketing petroleum products, and providing management and support services to its subsidiaries.

Wynnewood Refining Company (“WRC”), a wholly owned subsidiary of GWEC, is incorporated in Delaware. WRC’s primary activity is operating a refinery in Wynnewood, Oklahoma that has a capacity of approximately 70,000 barrels per day (“bpd”).

Wynnewood Insurance Corporation (“WIC”), a wholly owned subsidiary of GWEC, is incorporated in Hawaii. WIC’s primary activity is to provide a portion of the insurance coverage required by WRC.

References to the “Company” are to GWEC and its subsidiaries, collectively.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation—The accompanying unaudited consolidated financial statements include the accounts of GWEC and its wholly owned subsidiaries and have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”) for interim financial information. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the Company’s consolidated financial statements for the year ended December 31, 2010. Operating results for the nine months ended September 30, 2011, are not necessarily indicative of the results that may be expected for the year ending December 31, 2011, or for any other period.

Intercompany balances and transactions have been eliminated.

Subsequent Events—The Company evaluates events and transactions that occur after the balance sheet date but before the financial statements are issued. The Company evaluated such events and transactions through December 6, 2011, which is the day the consolidated financial statements were available to be issued.

Use of Estimates—The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Some of the most significant areas in which management uses estimates and assumptions are in determining impairments of long-lived assets, in establishing estimated useful lives for long-lived assets, provision for uncollectible accounts receivable, in valuing inventory, and in the determination of liabilities, if any, for legal contingencies.

The Company evaluates these estimates on an ongoing basis using historical experience and other methods the Company considers reasonable based on the particular circumstances.

 

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Nevertheless, actual results may differ significantly from the estimates. Any effects on the financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Cash, Cash Equivalents, and Investments—For purposes of these statements, the Company considers liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments, accounted for as available-for-sale, having an original maturity of more than three months, but less than 12, are recorded as a current asset in the accompanying consolidated balance sheets. Cash equivalents consist of money market funds and investments consist of equity securities and domestic and international bond funds.

Restricted Cash—Restricted cash includes cash balances which are legally or contractually restricted to use. At September 30, 2011 and December 31, 2010 the Company had short-term restricted cash of $124,782 and $124,101, respectively. The restricted cash is being held in a certificate of deposit as collateral on a bond that was initially set up to secure a right of way obligation on properties the Company previously owned. The Company is in the process of canceling the bond and releasing the restriction on the cash.

Allowance for Doubtful Accounts—The Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables. The Company establishes or adjusts the allowance as necessary using the specific identification method. The Company considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers that might impact collectibility. The allowance for doubtful accounts was $839,183 and $203,964 at September 30, 2011 and December 31, 2010, respectively. For the nine months ended September 30, 2011, the Company recorded provisions for bad debts of $839,183.

Commodity Derivative Instruments—The Company periodically enters into commodity swaps to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the purchase of raw materials and the marketing of refined products. Provisions in the Company’s Risk Management Policy set forth quantity limits, authorization requirements, and exposure limits.

In all instances, the Company has decided not to designate its derivative activities as hedges. As a result, the gains or losses from the changes in fair value of the derivative instruments have been recognized as a component of operating expense. Generally, the Company incurs accounting losses on derivatives during periods where net margins are rising and gains during periods where net margins are falling, which may cause significant fluctuations in the Company’s consolidated balance sheets and consolidated statements of operations. At September 30, 2011, the Company had a derivative liability of $7,435,210 net of a collateral balance of $31,200,000 held by its counterparty. For the nine months ended September 30, 2011, the Company recognized a realized loss of $22,897,515 and an unrealized loss of $37,853,684 in operating expense for commodity swaps.

At September 30, 2011 the Company had the following commodity swap positions:

 

Period

   Volume
(bpd)
     Weighted
Average
Fixed Price
     Weighted
Average
Fair Value Price
     Fair
Value
 

October 1, 2011 through December 31, 2011

     24,000       $ 11.59       $ 28.74       $ (37,853,684
           

 

 

 

Total

            $ (37,853,684
           

 

 

 

The information presented above shows the daily volume of West Texas intermediate crude oil contracted for purchase for the specified period. There is an offsetting equal daily volume of refined products contracted for sale for that same period. The weighted average fixed price represents the net margin between the crude purchase prices and the product sales prices. Quoted market prices, from trading counterparties, are used to value commodity derivative instruments at fair value.

 

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At times the Company’s commodity derivative contracts under master netting arrangements include both asset and liability positions. The Company has elected to offset the fair value amount recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation.

Commodity swaps expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are currently with a highly rated market participant, and the Company controls its level of financial exposure. The commodity derivative contracts are executed under master agreements which allow the Company to elect early termination of all contracts with the counterparty. If the Company chooses to elect early termination, all asset and liability positions with the counterparty would be net settled at the time of election.

Financial Instruments—The Company’s financial instruments consist of cash, investments, accounts receivable, a note receivable, accounts payable, other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate their fair value due to their short maturities. The fair value of long-term debt is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, the carrying value of long-term debt (see note 3) approximates fair value because the interest rate on this debt approximates market yields for similar debt instruments.

Fair Value Measurements—A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, fair values determined by Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

The tables below present information about the Company’s financial assets and liabilities measured and recorded at fair value on a reoccurring basis and indicate the fair value hierarchy of the inputs utilized by the Company to determine the fair values as of September 30, 2011 and December 31, 2010.

 

     Quoted Prices in
Active Markets
(Level 1)
     Significant  Other
Observable Inputs
(Level 2)
     Counterparty and
Cash Collateral
Netting
    Total
September  30,
2011
 

Assets

          

Investments

   $ 322,480       $ —         $ —        $ 322,480   

Liabilities

          

Commodity derivative contracts

   $ —         $ 37,853,684       $ (31,200,000 )*    $ 6,653,684 ** 

 

     Quoted Prices in
Active Markets
(Level 1)
     Significant Other
Observable  Inputs
(Level 2)
     Total
December 31,
2010
 

Assets

        

Investments

   $ 372,786       $ —         $ 372,786   

 

* Amount represents the effect of legally enforceable master netting arrangements between the reporting entity and its counterparty and the receivable for cash collateral held by the same counterparty.
** Amount does not agree to the derivative liabilities in the consolidated balance sheet because it excludes the September 2011 settlement of $781,526.

The valuation methods used to measure financial instruments at fair value are as follows:

 

   

Commodity derivative contracts, consisting of swaps, are measured at fair value using the market approach. Quoted market prices, from trading counterparties, are used to value commodity derivative instruments.

 

   

Investments are measured at fair value using a market approach based on quotations from national securities exchanges.

 

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Inventories—Inventories are valued at the lower of first-in, first-out cost or market. Write-downs to market are charged to operating expense. Inventories at September 30, 2011 and December 31, 2010 are as follows:

 

     2011      2010  

Refined, unrefined, and intermediate products

   $ 121,272,478       $ 100,025,660   

Crude oil

     48,891,206         64,537,833   

Materials and supplies (valued at average cost)

     7,049,294         5,192,704   
  

 

 

    

 

 

 

Inventories

   $ 177,212,978       $ 169,756,197   
  

 

 

    

 

 

 

Property, Plant, and Equipment—The initial purchase and additions to property, plant, and equipment, including capitalized interest and certain costs allocable to construction, are recorded at cost. Ordinary maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method based on estimated useful lives ranging from 1 to 30 years. Gains or losses on sales or other dispositions of property appear in gain (loss) on disposal of assets in the consolidated statements of operations. Property, plant, and equipment under capital leases and related obligations is recorded at an amount equal to the present value of future minimum lease payments computed on the basis of the Company’s incremental borrowing rate or, when known, the interest rate implicit in the lease. Assets acquired under capital leases and leasehold improvements are amortized using the straight-line method over the lease term and are included in depreciation expense.

At September 30, 2011 and December 31, 2010, property, plant, and equipment, with the range of useful lives, are comprised of the following:

 

     2011     2010  

Refinery property, plant, and equipment (3 to 30 years)

   $ 329,744,106      $ 318,737,295   

Pipeline and copiers under capital lease (5 to 20 years)

     557,602        641,743   

Airplane (6 years)

     8,345,920        7,808,376   

Furniture, fixtures, and equipment (1 to 15 years)

     6,768,280        6,303,688   

Precious metals, land, and other non-depreciable assets

     4,052,526        3,663,655   

Catalyst (5 years)

     7,450,553        7,484,385   

Vehicles (2 to 3 years)

     1,297,583        1,162,311   

Construction in progress

     8,880,683        7,179,785   
  

 

 

   

 

 

 

Property, plant, and equipment—at cost

     367,097,253        352,981,238   

Less accumulated depreciation and amortization (including accumulated depreciation under capital lease of $58,084 and $119,912, respectively)

     (86,743,620     (73,744,668
  

 

 

   

 

 

 

Property, plant, and equipment—net

   $ 280,353,633      $ 279,236,570   
  

 

 

   

 

 

 

Construction in progress consists of projects primarily related to additions and expansions to refinery processing units and replacements to the refinery plant and equipment. When the project is completed and placed in service, the costs are depreciated over their estimated life.

Major construction projects qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying the Company’s weighted average interest rate from long-term debt by the amount of qualifying costs. As major construction projects are completed, the associated capitalized interest is amortized over the useful life of the asset with the underlying cost of the asset. For the nine months ended September 30, 2011 and 2010, the Company capitalized interest of $832,663 and $5,718,092, respectively.

Depreciation and amortization expense for the nine months ended September 30, 2011 and 2010 was $13,083,093 and $10,610,912, respectively.

 

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Intangible Assets—Intangible assets consist of the cost of two processing licenses obtained for two refinery units, which are subject to amortization. Amortization is provided using the straight-line method based on an estimated useful life of 19 years. Amortization expense for the nine months ended September 30, 2011 and 2010 was $49,759 and $18,970, respectively.

The gross carrying amount and accumulated amortization totals related to the Company’s intangible assets are as follows:

 

     Gross Carry
Value
     Accumulated
Amortization
    Net Carrying
Value
 

As of September 30, 2011

       

Processing license—sulfur recovery unit

   $ 480,566       $ (132,788   $ 347,778   

Processing license—gasoline hydrotreater

     780,000         (37,632     742,368   
  

 

 

    

 

 

   

 

 

 

Total

   $ 1,260,566       $ (170,420   $ 1,090,146   
  

 

 

    

 

 

   

 

 

 

As of December 31, 2010

       

Processing license—sulfur recovery unit

   $ 480,566       $ (113,818   $ 366,748   

Processing license—gasoline hydrotreater

     780,000         (6,842     773,158   
  

 

 

    

 

 

   

 

 

 

Total

   $ 1,260,566       $ (120,660   $ 1,139,906   
  

 

 

    

 

 

   

 

 

 

Estimated amortization expense for succeeding years are as follows:

 

Year

   Amortization
Expense
 

2011

   $ 16,586   

2012

     66,346   

2013

     66,346   

2014

     66,346   

2015

     66,346   

Thereafter

     808,176   
  

 

 

 

Total

   $ 1,090,146   
  

 

 

 

Debt Issuance Costs—The Company capitalizes direct costs incurred to issue or modify debt agreements. Unamortized debt issuance costs are included in noncurrent or current other assets on the consolidated balance sheets. For the nine months ended September 30, 2011 and 2010, the Company capitalized $1,407,277 and $2,903,539, respectively, of costs incurred in connection with debt amendments. These costs are being amortized over the expected term of their respective financings and are included in interest expense. Costs associated with revolving debt are amortized on a straight-line basis and costs associated with debt agreements having scheduled payoffs are amortized using the effective interest method. For the nine months ended September 30, 2011, total interest expense from deferred debt issuance costs was $5,443,280, of which $2,208,617 represented a write off of a portion of unamortized debt issuance costs from amending and prepaying debt. For the nine months ended September 30, 2010, the Company amortized deferred debt issuance costs of $3,483,830.

Debt Issued at a Discount—Debt issued at a discount to the face amount is accreted up to its face amount utilizing the effective interest method over the expected term of the note and recorded as a component of interest expense on the consolidated statements of operations.

Impairment—The Company’s long-lived assets are periodically reviewed for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Impairments, if any, are measured as the amount by which the carrying amount of the asset exceeds the forecast of discounted expected future cash flows. The Company recorded no impairments during the nine months ended September 30, 2011 and 2010, respectively.

 

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Asset Retirement Obligation—The Company evaluates legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of a long-lived asset, and recognizes a liability equal to the estimated fair value of the asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability is accreted over time as an operating expense using a systematic and rational method.

The Company has asset retirement obligations with respect to certain of its refinery assets due to various legal obligations to clean and/or dispose of various component parts of the refinery at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is the Company’s practice and current intent to maintain the refinery assets and continue making improvements to those assets based on technological advances. As a result, management believes that the refinery has an indeterminate life for purposes of estimating asset retirement obligations because dates or ranges of dates upon which the Company would retire refinery assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any component part of the refinery, a liability will be recorded based on the estimated cost to perform the asset retirement activity at the fair value of those costs using established present value techniques. The Company will continue to monitor and evaluate its potential asset retirement obligations.

Deferred Turnaround Costs—Refinery turnaround costs are incurred in connection with planned shutdown and inspections of the refinery’s major units to perform planned major maintenance. Refinery turnaround costs are deferred when incurred and amortized on a straight-line basis over that period of time estimated to lapse until the next planned turnaround occurs, generally four years. Refinery turnaround costs include, among other things, the cost to repair, restore, refurbish, or replace refinery equipment such as tanks, reactors, piping, rotating equipment, instrumentation, electrical equipment, heat exchangers, and fired heaters. A major turnaround was performed in the second quarter of 2008 and the next major turnaround is scheduled to be performed in the fourth quarter of 2012. As of September 30, 2011 and December 31, 2010, deferred turnaround costs amounted to $14,208,158 and $24,044,574, net of accumulated amortization of $47,666,875 and $37,830,459, respectively. Amortization expense for the nine months ended September 30, 2011 and 2010 was $9,836,416 and $10,466,956, respectively.

Revenue Recognition—The Company generates revenue primarily from the sale of refined products produced at the Company’s refinery and refined products purchased directly from outside sources. In general, the Company enters into spot and short-term agreements that stipulate the terms and conditions of the sales. Revenue is recorded as products are delivered to customers, which is the point at which title and risk of loss are transferred. Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the consolidated statements of operations.

The Company also engages in trading activities, whereby the Company enters into agreements to purchase and sell refined products with third parties. The Company acts as principle in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards of ownership. The Company records revenue for the gross amount of the sales transactions, and records cost of purchases as an operating expense in the accompanying consolidated financial statements.

Excise tax, motor fuel tax, sales tax, and other taxes invoiced to customers and payable to government agencies are recorded on a net basis with the tax portion of a sales invoice directly credited to a liability account.

Comprehensive Income (Loss)—Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes unrealized gains and losses from available-for-sale securities.

 

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Environmental Costs and Other Contingencies

Environmental Costs—The Company records an undiscounted liability on the consolidated balance sheets as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of the liabilities are based on currently available facts, existing technology, and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience, and data released by the United States Environmental Protection Agency (“EPA”) or other organizations. The estimates are subject to revision in future periods based on actual costs or new circumstances.

Other Contingencies—The Company recognizes a liability for other contingencies when the Company has an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome can be estimated, the Company accrues a liability for that amount. Alternatively, where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Recent Accounting Pronouncements—In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-05, Comprehensive Income (Topic 220)—Presentation of Comprehensive Income. ASU 2011-05 requires entities to present net income and other comprehensive income in either a single continuous statement or in two separate, but consecutive, statements of net income and other comprehensive income. ASU 2011-05 is effective for fiscal years and interim periods beginning after December 15, 2011. The Company does not expect the adoption of ASU 2011-05 to have a material impact on its results of operations, financial condition, or cash flows.

In May 2011, the FASB issued ASU No. 2011-04 that amends Accounting Standards Codification (“ASC”) 820Fair Value Measurement regarding fair value measurements and disclosure requirements. ASC 820 provides a framework for how companies should measure fair value when used in financial reporting, and sets out required disclosures. The amendments are intended to clarify how fair value should be measured, converge the U.S. guidance with International Financial Reporting Standards, and expand the disclosures that are required. The amendments are effective during interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. The Company does not expect that the adoption of ASU 2011-04 to have a material effect on its results of operations, financial condition, or cash flows.

3. LONG-TERM DEBT

 

     September 30, 2011     December 31, 2010  

Term loan—due November 2014

   $ 49,212,121      $ 96,250,000   

Finance obligation—due September 2029

     19,693,658        19,828,228   

Capital lease obligation—due September 2029

     30,461,266        30,804,621   

Airplane loan—due March 2014

     4,605,033        4,734,717   

Other notes—due February 2011

     —          5,412   

Less discount on term loan

     (3,747,825     (7,364,382
  

 

 

   

 

 

 

Total debt

     100,224,253        144,258,596   

Less obligations due in one year

     (46,401,137     (14,582,463
  

 

 

   

 

 

 

Long-term debt

   $ 53,823,116      $ 129,676,133   
  

 

 

   

 

 

 

Term Loan—GWEC, WRC, and the Holding Company, collectively, are a party to a secured five-year $110,000,000 discounted term loan facility (the “Term Loan”) dated November 13, 2009 (as amended) with a syndicate of financial institutions. Borrowings under the Term Loan accrue interest on floating rates based on

 

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LIBOR or the agent’s prime rate at the Company’s option. Borrowings were repayable quarterly starting December 31, 2009, with 10% of the principal payable in year’s one and two, 20% payable in year’s three and four, and 40% payable in year five, with the last scheduled payment due on September 30, 2014. The term loan allows for prepayment and is also subject to mandatory prepayment requirements with respect to certain asset sales, excess cash flow (as defined in the agreement), and certain other events. Prepayments are applied pro rata to the remaining scheduled term loan principal payments. The Company voluntarily prepaid $40,000,000 in the third quarter of 2011. The Company estimates a mandatory prepayment of $43,060,606 will be due on March 30, 2012 with respect to the year ended December 31, 2011 excess cash flow provision. At September 30, 2011, the Company had $49,212,121 outstanding under the facility.

Revolver—GWEC, WRC, and the Holding Company, collectively, entered into a $150,000,000 secured revolving credit facility (the “Revolver”) dated November 13, 2009 with a syndicate of financial institutions. On August 19, 2011, the credit facility was amended to extend the term to August 19, 2016, increase the borrowing base to $175,000,000, and reduce the interest rates. The Company can borrow and/or issue letters of credit, which in the aggregate, cannot exceed the lesser of the borrowing base or $175,000,000. The borrowing base is limited by the balances of cash, accounts receivable, inventory, exchange balances, and outstanding letters of credit for which no payable yet exists. The borrowing base was $175,000,000 at September 30, 2011. Borrowings under this facility accrue interest based on LIBOR or base rate options plus a margin based on the Company’s fixed charge coverage ratio. Borrowings are repayable at expiration of the revolving facility on August 19, 2016. There was no outstanding Revolver balance at September 30, 2011.

Letters of credit are primarily obtained by the Company for its routine purchases of crude oil. Letters of credit totaling $26,397,012 and $30,624,143 had been issued as of September 30, 2011 and December 31, 2010, respectively.

The Term Loan and Revolver are secured by substantially all of GWEC’s and WRC’s assets and are subject to various financial and non-financial covenants that limit distributions, dividends, acquisitions, capital expenditures, disposals and debt and require minimum debt service coverage, net worth, and working capital requirements. The Company was in compliance with its financial covenants and ratios at September 30, 2011.

Airplane Loan—GWEC has a $5,300,000 loan with a bank. Under the agreement, interest is payable at a fixed rate for the first three years and at a variable rate based on the 30-day LIBOR for the remaining four years. The loan is to be repaid over seven years with principal payments based on a 20-year amortization period and a balloon payment at the end of the seventh year in 2014. The loan is secured by the airplane. The outstanding balance at September 30, 2011 was $4,605,033.

Finance Obligation—On September 9, 2009, WRC sold its bulk terminal and loading facility for $20,000,000. WRC, in turn, agreed to lease back those same assets for 10 years with two five year renewal options. Under the terms of the lease agreement, WRC is required to support the operations of the terminal and loading facility at its own risk and GWEC has guaranteed WRC’s lease payments. Due to these various forms of continuing involvement, the transaction was recorded under the finance method of accounting. Accordingly, the value of the terminal and loading facility remain on the Company’s books and are continuing to be depreciated over their remaining useful lives. The proceeds received have been recorded as a finance obligation. The obligation is payable in monthly installments. The outstanding balance at September 30, 2011 was $19,693,658.

Capital Lease—On September 9, 2009, WRC entered into a sale-leaseback transaction where WRC sold a 49 mile pipeline for $32,000,000 and leased back the same pipeline for a term of 20 years. The transaction was recorded using sale-leaseback accounting. The gain of $30,741,039 is being deferred as an offset to the leased pipeline and is being amortized in proportion to the leased pipeline over the term of the lease. The lease is payable in monthly installments. The outstanding balance at September 30, 2011 was $30,461,266.

 

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Letters of credit fees, bond fees, unused commitment fees, amortization of deferred debt issuance costs, write off of deferred debt issuance costs, accretion of discount on debt, amortization of premium on interest rate cap, and interest from borrowings under the various agreements are included in interest expense in the accompanying consolidated statements of operations (net of amounts capitalized).

The minimum remaining principal payments under the loan agreements and minimum lease payments under capital lease obligations are as follows:

 

Year Ending December 31,

   Term
Loan
     Airplane
Loan
     Finance
Obligation
     Capital
Lease
    Total  

2011

   $ 3,075,758       $ 44,583       $ 57,281       $ 1,092,000      $ 4,269,622   

2012

     46,136,363         185,403         253,518         4,392,000        50,967,284   

2013

     —           197,250         322,103         4,380,000        4,899,353   

2014

     —           4,177,797         398,302         4,380,000        8,956,099   

2015

     —           —           482,881         4,380,000        4,862,881   

Thereafter

     —           —           18,179,573         60,357,058        78,536,631   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total minimum lease payments

   $ 49,212,121       $ 4,605,033       $ 19,693,658         78,981,058        152,491,870   
  

 

 

    

 

 

    

 

 

      

Less amount representing executory costs

              (4,406,433     (4,406,433
           

 

 

   

 

 

 

Net minimum lease payments

              74,574,625        148,085,437   

Less amount representing interest

              (44,113,359     (44,113,359
           

 

 

   

 

 

 

Present value of net minimum lease payments

            $ 30,461,266      $ 103,972,078   
           

 

 

   

 

 

 

4. TAX DIVIDEND OBLIGATION TO PARENT

GWEC and its subsidiaries are S Corporations for income tax purposes. In general, as an S Corporation, GWEC and its subsidiaries are not taxable, and taxable income and deductions flow from GWEC and its subsidiaries to TGWC, where the income is taxed at the shareholder level. Prior to October 1, 2009, the Company reimbursed TGWC for the computed state and federal income taxes based on the Company’s net income and a combined rate of approximately 33%. On November 13, 2009, with the creation of the Holding Company, a new tax agreement (effective October 1, 2009) was entered into between the Holding Company, its subsidiaries, and TGWC. Pursuant to this agreement, GWEC reimburses the Holding Company for the computed state and federal income taxes based on GWEC’s net taxable income and a combined rate of 40%, the rate that GWEC would pay if it determined its tax liability as a stand alone C Corporation. These amounts are reflected as tax dividends declared in the consolidated statements of changes in retained earnings. Each of GWEC’s subsidiaries reimburses GWEC on the same basis. When GWEC recognizes a net loss, such loss multiplied by 40% reduces its tax reimbursement liability in future years.

5. EMPLOYEE BENEFIT PLANS

The Company has two profit sharing plans (defined contribution plans), one covering certain nonunion employees and one covering union employees. The employees must meet eligibility requirements as to age and length of service. Contributions to the plans are determined annually by the Company. Contributions of $1,974,412 and $1,226,786 were expensed for the nine months ended September 30, 2011 and 2010, respectively.

6. CONCENTRATIONS

Substantially all of the Company’s accounts receivable at September 30, 2011 and December 31, 2010 results from the sale of refined products to companies in the retail and wholesale distribution market. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that

 

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these entities may be similarly affected by industry-wide changes in economic and other conditions. Such receivables are generally not collateralized. However, the Company performs credit evaluations on its customers to minimize the exposure to credit risk. No single customer accounted for more than 10% of product sales for the nine months ended September 30, 2011 and 2010, respectively. One customer accounted for more than 10% of gross accounts receivable at September 30, 2011 and no single customer accounted for more than 10% of gross accounts receivable at December 31, 2010.

In March 2010, the Company was awarded contracts to sell approximately 58,000,000 gallons of jet fuel to the United States Defense Energy Support Center (“DESC”) for the period April 1, 2010 through March 31, 2011. This agreement was subsequently amended to run through May 31, 2011. In May 2011, the Company was awarded contracts to sell approximately 17,955,000 gallons of jet fuel to the DESC for the period June 1, 2011 through September 30, 2011. Pricing is variable, calculated based on market prices, as specified in the contract. For the nine months ended September 30, 2011 and 2010, product sales to this customer approximated 6%, respectively, of total operating revenue.

In addition, substantially all of the Company’s raw materials purchased for refinery production and refined products purchased for resale are from companies in the oil and gas exploration and production industry in the United States. This concentration of suppliers may impact the Company’s overall costs and/or profitability, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic and other conditions. For the nine months ended September 30, 2011 and 2010, three vendors accounted for 39% and 44%, respectively, of total raw material and refined purchases.

Approximately 50% of the Company’s labor force is covered by a collective bargaining agreement that is subject to review and renewal on a regular basis. The current collective bargaining agreement is due to expire in June 2012.

7. RELATED-PARTY TRANSACTIONS

GWEC has an agreement with an affiliate, as amended and renewed in May 2011, to sublease a hangar for the Company aircraft. Terms of the sublease provide for annual rentals of $87,000 until June 30, 2013.

On a monthly basis, the Company charges certain general and administrative support costs to its affiliates. At September 30, 2011 and December 31, 2010, the affiliated accounts receivable balance was $197,815 and $174,543, respectively.

GWEC entered into a promissory note in February 2010 with TGWC, whereby GWEC promised to pay TGWC the principal sum of $10,000,000 or such lesser amount the borrower shall borrow from the lender. Interest on the unpaid principal balance is computed daily based on the prime rate. All amounts borrowed, together with interest, are to be paid no later than ten business days after the funds are advanced. The note is due on January 31, 2012. There was no outstanding balance under the note at September 30, 2011 and December 31, 2010, respectively.

8. COMMITMENTS AND CONTINGENCIES

Legal Matters—In the ordinary course of business, the Company is a party to various other legal matters. In the opinion of management, none of these matters, either individually or in the aggregate, will have a material effect on the Company’s financial condition, liquidity, or results of operations.

Health, Safety, and Environmental Matters—The Company is subject to certain environmental, safety, and other regulations primarily administered by the EPA and various state agencies. In addition, the EPA requires that the Company provide assurance of its financial wherewithal regarding certain future closure costs of the facility. Except as discussed below, management of the Company believes it has complied with all material aspects associated with these regulations.

 

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Other Matters—TGWC entered into a 10-year lease agreement extension for office space in June 2003. The Company pays all rent and occupancy costs in exchange for its use of the office space. The Company has guaranteed the performance of TGWC’s obligations, under which the Company could be legally obligated to pay annual rent, as scheduled below, and annual occupancy costs of $356,918 with provisions for escalation based on actual expenses. The monthly rent is expensed on a straight-line basis over the term of the office lease. Rent expense, including occupancy costs, for the nine months ended September 30, 2011 and 2010 was $637,114 and $649,849, respectively.

The aggregate minimum rental commitments under non-cancelable leases for the periods shown at September 30, 2011, are as follows:

 

Year

   Annual Rent  

2011

   $ 158,526   

2012

     634,102   

2013

     317,051   
  

 

 

 
   $ 1,109,679   
  

 

 

 

The Company currently has one throughput and deficiency agreement that expires in 2020. Under the terms of the agreement, the Company is obligated to pay a tariff fee on a minimum daily volume of crude or else pay for any deficiencies. The fees paid under throughput and deficiency obligations for the nine months ended September 30, 2011 and 2010 were $2,948,400 and $6,114,228, respectively.

At September 30, 2011, the minimum commitments under the throughput and deficiency agreement are as follows:

 

Year

   Transportation
Obligation
 

2011

   $ 993,600   

2012

     3,952,800   

2013

     3,942,000   

2014

     3,942,000   

2015

     3,942,000   

Thereafter

     17,074,800   
  

 

 

 
   $ 33,847,200   
  

 

 

 

On March 14, 2011, WRC and GWEC, collectively, entered into a 15-year sulfur processing agreement with a third party. Under the terms of the agreement, the third party will process and remove sulfur from specified acid gas, sour water stripper gas and other streams containing hydrogen sulfide or other forms of sulfur that are generated as a byproduct of the operation of the Company’s refinery for a guaranteed minimum monthly processing fee of $200,000. The payment of the monthly processing fee will start after the third party installs their proprietary equipment at the Company’s refinery, which the Company estimates to be November 1, 2012.

 

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Assuming operability of the proprietary equipment on November 1, 2012, the aggregate minimum commitments under the operating agreement for the periods shown at September 30, 2011 are as follows:

 

Year

   Processing
Obligation
 

2011

   $ —     

2012

     400,000   

2013

     2,400,000   

2014

     2,400,000   

2015

     2,400,000   

Thereafter

     28,400,000   
  

 

 

 
   $ 36,000,000   
  

 

 

 

9. SUBSEQUENT EVENT

On November 2, 2011, the Holding Company entered into an agreement to sell its stock to Coffeyville Resources, LLC for $525,000,000, plus working capital on the closing date. The Company expects the transaction to close by the end of the fourth quarter of 2011.

******

 

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Independent Auditors’ Report

To the Board of Directors and Shareholder of

Gary-Williams Energy Corporation

Denver, Colorado

We have audited the accompanying consolidated balance sheet of Gary-Williams Energy Corporation (the “Company”) as of December 31, 2010, and the related consolidated statements of operations, changes in shareholder’s equity, comprehensive income (loss), and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of the Company for the year ended December 31, 2009 and 2008 were audited by other auditors whose report, dated March 30, 2010, expressed an unqualified opinion on those statements.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such 2010 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2010, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 31, 2011

 

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Independent Auditors’ Report

The Board of Directors and Shareholder

Gary-Williams Energy Corporation:

We have audited the accompanying consolidated balance sheet of Gary-Williams Energy Corporation and subsidiaries (the Company) as of December 31, 2009, and the related consolidated statements of operations, changes in shareholder’s equity, comprehensive income (loss), and cash flows for each of the years in the two-year period then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gary-Williams Energy Corporation and subsidiaries as of December 31, 2009, and the results of their operations and their cash flows for each of the years in the two-year period then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Denver, Colorado

March 30, 2010

 

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GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Balance Sheets

As of December 31, 2010 and 2009

 

     2010      2009  

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 34,045,795       $ 5,971,551   

Restricted cash

     124,101         308,481   

Investments

     372,786         341,317   

Accounts receivable:

     

Trade—net of allowances of $203,964 and $2,946,415 in 2010 and 2009, respectively

     63,732,241         54,265,176   

Affiliates

     174,543         163,877   

Insurance recovery

     —           303,335   

Note receivable affiliate

     894         3,958   

Inventories

     169,756,197         162,815,841   

Prepaid expenses and other current assets

     4,001,060         4,354,762   
  

 

 

    

 

 

 

Total current assets

     272,207,617         228,528,298   
  

 

 

    

 

 

 

Property, plant, and equipment—net

     279,236,570         253,455,013   

Deferred turnaround costs—net

     24,044,574         37,790,336   

Intangible assets—net

     1,139,906         392,041   

Other assets—net

     9,910,006         11,759,028   
  

 

 

    

 

 

 

Total assets

   $ 586,538,673       $ 531,924,716   
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Balance Sheets

As of December 31, 2010 and 2009

 

     2010      2009  

Liabilities and Shareholder’s Equity

     

Current liabilities:

     

Accounts payable

   $ 215,522,352       $ 168,497,331   

Accrued liabilities and other

     18,285,313         18,151,441   

Long-term debt—current portion—net of discount

     14,582,463         11,739,262   
  

 

 

    

 

 

 

Total current liabilities

     248,390,128         198,388,034   
  

 

 

    

 

 

 

Noncurrent liabilities:

     

Long-term debt—net of discount

     129,676,133         141,163,405   

Other

     76,859         121,099   
  

 

 

    

 

 

 

Total noncurrent liabilities

     129,752,992         141,284,504   
  

 

 

    

 

 

 

Total liabilities

     378,143,120         339,672,538   
  

 

 

    

 

 

 

Commitments and contingencies (Note 8)

     

Shareholder’s equity:

     

Common stock, $0.01 par value—authorized 150,000 voting shares; issued and outstanding 96,900 shares Authorized 150,000 nonvoting shares; none issued

     969         969   

Contributed capital

     36,357,640         36,357,640   

Retained earnings

     172,034,444         155,889,012   

Accumulated other comprehensive income

     2,500         4,557   
  

 

 

    

 

 

 

Total shareholder’s equity

     208,395,553         192,252,178   
  

 

 

    

 

 

 

Total liabilities and shareholder’s equity

   $ 586,538,673       $ 531,924,716   
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Statements of Operations

For the Years ended December 31, 2010, 2009 and 2008

 

     2010     2009     2008  

Operating revenue

   $ 2,141,043,605      $ 1,649,568,577      $ 2,142,815,015   

Operating expenses

     2,086,819,478        1,566,500,099        2,248,855,202   
  

 

 

   

 

 

   

 

 

 

Gross profit

     54,224,127        83,068,478        (106,040,187

General and administrative expenses

     15,767,934        17,881,095        20,584,971   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     38,456,193        65,187,383        (126,625,158
  

 

 

   

 

 

   

 

 

 

Other income (expense):

      

Interest and investment income

     40,623        144,607        1,065,591   

Interest expense

     (22,432,421     (13,104,572     (7,419,241

Gain on disposal of assets

     12,052        210,254        1,900,377   

Other—net

     68,985        278,438        2,935,035   
  

 

 

   

 

 

   

 

 

 

Total other expense

     (22,310,761     (12,471,273     (1,518,238
  

 

 

   

 

 

   

 

 

 

Net income (loss) from continuing operations

     16,145,432        52,716,110        (128,143,396

Net loss from discontinued operations

     —          (253,242     (1,618,789
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 16,145,432      $ 52,462,868      $ (129,762,185
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Statements of Changes in Shareholder’s Equity

For The Years ended December 31, 2010, 2009 and 2008

 

    Number of
Common
Shares
    Common
Stock
    Number of
Preferred
Shares
    Preferred
Stock
    Contributed
Capital
    Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
    Total
Shareholder’s
Equity
 

Balance at December 31, 2007

    96,900      $ 969        3,673      $ 37      $ 18,410,485      $ 234,088,374      $ (5,213   $ 252,494,652   

Contributed capital

    —          —          —          —          17,947,118        —          —          17,947,118   

Net loss

    —          —          —          —          —          (129,762,185     —          (129,762,185

Other comprehensive income

    —          —          —          —          —          —          3,730        3,730   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance—December 31, 2008

    96,900      $ 969        3,673      $ 37      $ 36,357,603      $ 104,326,189      $ (1,483   $ 140,683,315   

Subsidiary stock dividend

    —          —          —          —          —          (900,045     —          (900,045

Cancelation of preferred stock and capital contribution

    —          —          (3,673     (37     37        —          —          —     

Net income

    —          —          —          —          —          52,462,868        —          52,462,868   

Other comprehensive income

    —          —          —          —          —          —          6,040        6,040   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance—December 31, 2009

    96,900      $ 969        —          —        $ 36,357,640      $ 155,889,012      $ 4,557      $ 192,252,178   

Net income

    —          —          —          —          —          16,145,432        —          16,145,432   

Other comprehensive loss

    —          —          —          —          —          —          (2,057     (2,057
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance—December 31, 2010

    96,900      $ 969        —          —        $ 36,357,640      $ 172,034,444      $ 2,500      $ 208,395,553   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Index to Financial Statements

GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Statements of Comprehensive Income (Loss)

For the Years ended December 31, 2010, 2009 and 20008

 

     2010     2009      2008  

Net income (loss)

   $ 16,145,432      $ 52,462,868       $ (129,762,185

Unrealized gain (loss) on investments

     (2,057     6,040         3,730   
  

 

 

   

 

 

    

 

 

 

Comprehensive income (loss)

   $ 16,143,375      $ 52,468,908       $ (129,758,455
  

 

 

   

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Statements of Cash Flows

Years ended December 31, 2010, 2009 and 2008

 

     2010     2009     2008  

Cash flows from operating activities:

      

Net income (loss)

   $ 16,145,432      $ 52,462,868        (129,762,185

Net loss from discontinued operations

     —          253,242        1,618,789   
  

 

 

   

 

 

   

 

 

 

Net income (loss) from continuing operations

     16,145,432        52,716,110        (128,143,396

Adjustments to reconcile net income from continuing operations to net cash provided by operating activities:

      

Depreciation and amortization

     14,728,920        13,765,339        13,280,570   

Amortization of turnaround costs

     13,745,762        15,401,851        9,420,376   

Amortization of deferred financing costs and discount on debt

     7,744,411        4,606,802        292,783   

Gain on sale of assets

     (12,052     (210,254     (1,900,377

Realized gain on sale of investments, net

     (4,534     (13     (3,594

Impairment of assets

     —          —          566,619   

Provision for losses on accounts receivable

     —          673,255        2,273,160   

Other

     —          2,404        —     

Changes in operating assets and liabilities:

      

(Increase) decrease in accounts receivable—net)

     (9,303,930     12,472,505        10,058,278   

(Increase) decrease in accounts receivable—affiliate)

     (10,666     9,032        276,070   

(Increase) decrease in inventories

     (6,940,356     (83,542,851     147,649,806   

Decrease (increase) in prepaid expenses

     353,702        (378,266     645,371   

Increase in deferred turnaround costs

     —          (3,008,930     (54,193,091

(Increase) decrease in other assets)

     (22,923     37,323        —     

Increase (decrease) in accounts payable

     49,856,043        70,842,159        (85,463,402

Increase (decrease) in accrued liabilities

     114,169        4,025,705        (8,860,971

Decrease in deferred revenue and other

     (24,537     (7,658     (9,115
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

     86,369,441        87,404,513        (94,110,913
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Capital expenditures—refinery and pipeline

     (43,310,966     (49,444,657     (37,471,979

Processing license expenditure

     (780,000     —          —     

Proceeds from sale of assets, net

     13,652        4,244,856        4,206,983   

Proceeds from property insurance

     117,984        2,525,000        1,838,747   

Proceeds from sale-leaseback of pipeline

     —          31,830,451        —     

Note receivable collections

     —          —          65,077   

Purchase of investments

     (327,412     (2,384     (15,222

Proceeds from sale of investments

     320,635        1,744        254,365   

Note receivable—related-party

     —          (250,000     (7,000

Note receivable—related-party collection

     3,064        250,638        300,000   

Change in restricted cash

     308,080        (308,481     —     
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (43,654,963     (11,152,833     (30,829,029
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements. (Continued)

 

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Index to Financial Statements

GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Consolidated Statements of Cash Flows

Years ended December 31, 2010, 2009 and 2008

 

     2010     2009     2008  

Cash flows from financing activities:

      

Borrowings under long-term debt

   $ 950,888,046      $ 923,000,000      $ 883,485,000   

Principal payments on long-term debt

     (962,198,607     (972,449,903     (775,359,716

Borrowings under notes payable to parent

     22,600,000        —          —     

Principal payments on notes payable to parent

     (22,600,000     (7,770,000     (1,000,000

Capital lease obligation payments

     (426,134     (102,735     (26,723

Payments of debt issuance costs

     (2,903,539     (14,450,766     (1,300,285

Payment of offering costs

     —          —          (40,202

Capital contribution by parent

     —          —          17,947,117   

Tax dividends distributed by parent

     —          —          (17,947,117
  

 

 

   

 

 

   

 

 

 

Net cash (used in) provided by financing activities

     (14,640,234     (71,773,404     105,758,074   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents—continuing operations

     28,074,244        4,478,276        (19,181,868

Change in cash and cash equivalents—discontinued operations:

      

Net cash used in operating activities

     —          (219,307     (1,623,856

Net cash used in investing activities

     —          (224,079     (30,487
  

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents

     28,074,244        4,034,890        (20,836,211

Cash and cash equivalents—Beginning of year

     5,971,551        1,936,661        22,772,872   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents—End of year

   $ 34,045,795      $ 5,971,551      $ 1,936,661   
  

 

 

   

 

 

   

 

 

 

Supplemental disclosures of cash flow information:

      

Cash paid during the year for interest and financing expenses—net of amounts capitalized

   $ 17,869,056      $ 22,501,293      $ 8,163,933   
  

 

 

   

 

 

   

 

 

 

Supplemental schedule of noncash investing and financing activities:

      

Additions to construction projects in progress funded through accounts payable

   $ 724,185        (1,245,880   $ 5,808,655   
  

 

 

   

 

 

   

 

 

 

Capital lease acquisition

     —        $ 557,602        —     
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements. (Concluded)

 

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Index to Financial Statements

GARY-WILLIAMS ENERGY CORPORATION

AND SUBSIDIARIES

(A Wholly Owned Subsidiary of GWEC Holding Company, Inc.)

Notes to Consolidated Financial Statements

As of and for the Years ended December 31, 2010, 2009 and 2008

1. Background And Organization

Gary-Williams Energy Corporation (“GWEC”) is incorporated in Delaware. GWEC became a wholly owned subsidiary of GWEC Holding Company, Inc. (the “Holding Company”) on October 30, 2009 when The Gary-Williams Company (“TGWC”), its then parent company, contributed all of its common shares of GWEC to the Holding Company and canceled its outstanding preferred stock. GWEC’s primary activities are purchasing refinery feedstocks, marketing petroleum products, and providing management and support services to its subsidiaries.

Wynnewood Refining Company (“WRC”), a wholly owned subsidiary of GWEC, is incorporated in Delaware. WRC’s primary activity is operating a refinery in Wynnewood, Oklahoma that has a capacity of approximately 70,000 barrels per day.

Wynnewood Insurance Corporation (“WIC”), a wholly owned subsidiary of GWEC, is incorporated in Hawaii. WIC’s primary activity is to provide a portion of the insurance coverage required by WRC.

Through April 30, 2009, GWEC owned all of the stock of Gary-Williams Production Company (“GWPC”). GWPC is engaged in the exploration, development, and operation of oil and gas properties located in the United States. On May 1, 2009, the Company spun-off GWPC to TGWC by declaring a dividend of all of its stock in GWPC. Prior year consolidated financial statements have been restated to present the operations of GWPC as a discontinued operation.

References to the “Company” are to GWEC and its subsidiaries, collectively.

2. Summary Of Significant Accounting Policies

Basis of Presentation—The accompanying consolidated financial statements include the accounts of its wholly owned subsidiaries and have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Intercompany balances and transactions have been eliminated.

Subsequent Events—The Company evaluates events and transactions that occur after the balance sheet date but before the financial statements are issued. The Company evaluated such events and transactions through March 31, 2011, which is the day the consolidated financial statements were available to be issued.

Use of Estimates—The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Some of the most significant areas in which management uses estimates and assumptions are in determining impairments of long-lived assets, in establishing estimated useful lives for long-lived assets, provision for uncollectible accounts receivable, in valuing inventory, and in the determination of liabilities, if any, for legal contingencies.

The Company evaluates these estimates on an ongoing basis using historical experience and other methods the Company considers reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on the financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

 

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Cash, Cash Equivalents, and Investments—For purposes of these statements, the Company considers liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments, accounted for as available-for-sale, having an original maturity of more than three months, but less than 12, are recorded as a current asset in the accompanying consolidated balance sheets. Cash equivalents consist of money market funds and investments consist of equity securities and domestic and international bond funds.

Restricted Cash—Restricted cash includes cash balances which are legally or contractually restricted to use. At December 31, 2010 and 2009, the Company had short-term restricted cash of $124,101 and $308,481, respectively. At December 31, 2009, the Company had long-term restricted cash of $123,700 included in other long-term assets. The restricted cash held at December 31, 2010 is being held in a certificate of deposit as collateral on a bond that was initially set up to secure a right of way obligation on properties the Company previously owned. The Company is in the process of canceling the bond and releasing the restriction on the cash.

Allowance for Doubtful Accounts—The Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables. The Company establishes or adjusts the allowance as necessary using the specific identification method. The Company considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers that might impact collectibility. The allowance for doubtful accounts was $203,964 and $2,946,415 at December 31, 2010 and 2009, respectively. For the years ended December 31, 2009 and 2008, the Company recorded provisions for bad debts of $673,255 and $2,723,160, respectively.

Futures Contracts—The Company periodically enters into futures contracts to hedge certain of its exposures to price fluctuations on raw materials and refined products. The purpose of these activities, as defined by the Company’s Risk Management Policy, is to enhance overall profits from WRC’s refining operations and to identify opportunities to generate a profit outside the refining operations in the Group III, Gulf Coast, and NYMEX markets. Other provisions in the Risk Management Policy set forth quantity limits, authorization requirements, and exposure limits for speculative positions.

In all instances, the Company has decided not to designate its derivative activities as hedges. As a result, the gains or losses from the changes in fair value of the derivative instruments have been recognized as a component of operating expense; however, the underlying hedged items have not been marked to market. The increases or decreases in the fair value of the underlying hedged items ultimately result in increases or decreases to operating revenue or operating expense at the time of sale. These changes are generally offset by the gains or losses from the changes in fair value of the derivative instruments and may increase earnings volatility. The Company had no futures contracts outstanding as of December 31, 2010 and 2009.

Derivative Financial Instrument—Interest rate cap agreements are used to reduce the potential impact of increases in interest rates on floating-rate long-term debt. At December 31, 2010, the Company was a party to an interest rate cap agreement covering 50% of its Term Loan balance or $48,125,000. The agreement entitles the Company to receive from the bank the amount, if any, by which the three month LIBOR interest rate exceeds 4% of the notional amount. The interest rate cap agreement is not designated as a cash flow hedge under applicable accounting standards and as such the change in fair value is recorded as adjustments to interest expense. The Company paid a premium of $47,000 for the interest rate cap and is amortizing this amount to interest expense over the term of the agreement. Unamortized premiums are included in noncurrent other assets on the consolidated balance sheets. The agreement expires on December 31, 2011.

Financial Instruments—The Company’s financial instruments consist of cash, investments, accounts receivable, a note receivable, accounts payable, other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate their fair value due to their short maturities. The

 

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Index to Financial Statements

fair value of long-term debt is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, the carrying value of long-term debt (see note 3) approximates fair value because the interest rate on this debt approximates market yields for similar debt instruments.

Inventories—Inventories are valued at the lower of first-in, first-out cost or market. Write-downs to market are charged to operating expense. Inventories at December 31, 2010 and 2009 are as follows:

 

     2010      2009  

Refined, unrefined, and intermediate products

   $ 100,025,660       $ 97,161,983   

Crude oil

     64,537,833         61,060,706   

Materials and supplies

     5,192,704         4,593,152   
  

 

 

    

 

 

 

Inventories

   $ 169,756,197       $ 162,815,841   
  

 

 

    

 

 

 

Property, Plant, and Equipment—The initial purchase and additions to property, plant, and equipment, including capitalized interest and certain costs allocable to construction, are recorded at cost. Ordinary maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method based on estimated useful lives ranging from 1 to 30 years. Gains or losses on sales or other dispositions of property appear in gain (loss) on disposal of assets in the consolidated statements of operations. Property, plant, and equipment under capital leases and related obligations is recorded at an amount equal to the present value of future minimum lease payments computed on the basis of the Company’s incremental borrowing rate or, when known, the interest rate implicit in the lease. Assets acquired under capital leases and leasehold improvements are amortized using the straight-line method over the lease term and are included in depreciation expense.

At December 31, 2010 and 2009, property, plant, and equipment, with the range of useful lives, are comprised of the following:

 

     2010     2009  

Refinery property, plant, and equipment (3 to 30 years)

   $ 318,737,295      $ 245,991,380   

Pipeline and copiers under capital lease (5 to 20 years)

     641,743        641,743   

Airplane (6 years)

     7,808,376        7,250,900   

Furniture, fixtures, and equipment (1 to 15 years)

     6,303,688        6,117,585   

Precious metals, land, and other non-depreciable assets

     3,663,655        3,457,371   

Catalyst (5 years)

     7,484,385        6,419,188   

Vehicles (2 to 3 years)

     1,162,311        1,136,199   

Construction in progress

     7,179,785        41,502,929   
  

 

 

   

 

 

 

Property, plant, and equipment—at cost

     352,981,238        312,517,295   

Less accumulated depreciation and amortization (including accumulated depreciation under capital lease of $119,912 and $75,203, respectively)

     (73,744,668     (59,062,282
  

 

 

   

 

 

 

Property, plant, and equipment—net

   $ 279,236,570      $ 253,455,013   
  

 

 

   

 

 

 

Construction in progress consists of projects primarily related to additions and expansions to refinery processing units and replacements to the refinery plant and equipment. When the project is completed and placed in service, the costs are depreciated over their estimated life.

Major construction projects qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying the Company’s weighted average interest rate from long-term debt by the amount of qualifying costs. As major construction projects are completed, the associated capitalized interest is amortized over the useful life of the asset with the underlying cost of the asset. For the years ended December 31, 2010, 2009 and 2008, the Company capitalized interest of $7,356,717, $2,037,342 and $136,648, respectively.

 

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Depreciation and amortization expense for the years ended December 31, 2010, 2009 and 2008 was $14,696,785, $13,740,046 and $13,272,057, respectively.

Intangible Assets—Intangible assets consist of the cost of two processing licenses obtained for two refinery units, which are subject to amortization. Amortization is provided using the straight-line method based on an estimated useful life of 19 years. Amortization expense for the years ended December 31, 2010, 2009 and 2008 was $32,135, $25,293 and $25,293, respectively.

The gross carrying amount and accumulated amortization totals related to the Company’s intangible assets are as follows:

 

     Gross Carry
Value
     Accumulated
Amortization
    Net Carrying
Value
 

As of December 31, 2010:

       

Processing license—sulfur recovery unit

   $ 480,566         (113,818   $ 366,748   

Processing license—gasoline hydrotreater

     780,000         (6,842     773,158   
  

 

 

    

 

 

   

 

 

 

Total

   $ 1,260,566         (120,660   $ 1,139,906   
  

 

 

    

 

 

   

 

 

 

As of December 31, 2009:

       

Processing license—sulfur recovery unit

   $ 480,566         (88,525   $ 392,041   
  

 

 

    

 

 

   

 

 

 

Total

   $ 480,566         (88,525   $ 392,041   
  

 

 

    

 

 

   

 

 

 

Estimated amortization expense for succeeding years are as follows:

 

Year

   Amortization
Expense
 

2011

   $ 66,346   

2012

     66,346   

2013

     66,346   

2014

     66,346   

2015

     66,346   

Thereafter

     808,176   
  

 

 

 

Total

   $ 1,139,906   
  

 

 

 

Debt Issuance Costs—Debt issuance costs represent loan origination fees paid to the lender and related professional service fees. Unamortized debt issuance costs are included in noncurrent other assets on the consolidated balance sheets. For the years ended December 31, 2010 and 2009, the Company capitalized $2,903,539 and $14,450,766, respectively, of costs incurred in connection with debt refinancing and amendments. These costs are being amortized over the terms of their respective financings and are included in interest expense. Costs associated with revolving debt are amortized on a straight-line basis and costs associated with debt agreements having scheduled payoffs are amortized using the effective interest method. The amortization of deferred debt issuance costs were $4,651,785, $4,063,812 and $292,783 for the years ended December 31, 2010, 2009 and 2008, respectively.

Debt Issued at a Discount—Debt issued at a discount to the face amount is accreted up to its face amount utilizing the effective interest method over the term of the note and recorded as a component of interest expense on the consolidated statements of operations.

Impairment—The Company’s long-lived assets are periodically reviewed for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Impairments, if any, are measured as the amount by which the carrying amount of the asset exceeds the forecast of discounted expected

 

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future cash flows. The Company recorded no impairments during the years ended December 31, 2010 and 2009, respectively. During the year ended December 31, 2008, the Company recorded an impairment charge of $528,119 to operating expenses for the loss in value of its precious metals.

Asset Retirement Obligation—The Company evaluates legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of a long-lived asset, and recognizes a liability equal to the estimated fair value of the asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability is accreted over time as an operating expense using a systematic and rational method.

The Company has asset retirement obligations with respect to certain of its refinery assets due to various legal obligations to clean and/or dispose of various component parts of the refinery at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is the Company’s practice and current intent to maintain the refinery assets and continue making improvements to those assets based on technological advances. As a result, management believes that the refinery has an indeterminate life for purposes of estimating asset retirement obligations because dates or ranges of dates upon which the Company would retire refinery assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any component part of the refinery, a liability will be recorded based on the estimated cost to perform the asset retirement activity at the fair value of those costs using established present value techniques. The Company will continue to monitor and evaluate its potential asset retirement obligations.

Deferred Turnaround Costs—Refinery turnaround costs are incurred in connection with planned shutdown and inspections of the refinery’s major units to perform planned major maintenance. Refinery turnaround costs are deferred when incurred and amortized on a straight-line basis over that period of time estimated to lapse until the next planned turnaround occurs, generally four years. Refinery turnaround costs include, among other things, the cost to repair, restore, refurbish, or replace refinery equipment such as tanks, reactors, piping, rotating equipment, instrumentation, electrical equipment, heat exchangers, and fired heaters. A major turnaround was performed in the second quarter of 2008 and the next major turnaround is scheduled to be performed in the fourth quarter of 2012. Although the Company performed the majority of its turnaround activities in the second quarter of 2008, the Company performed additional turnaround work on four of its refinery units in April 2009. In total, during the year ended December 31, 2009 and 2008, the Company incurred turnaround costs of $3,008,930 and $54,193,091, respectively. As of December 31, 2010 and 2009, deferred turnaround costs amounted to $24,044,574 and $37,790,336, net of accumulated amortization of $37,830,459 and $24,084,697, respectively. Amortization expense for the years ended December 31, 2010, 2009 and 2008 was $13,745,762, $15,401,851 and $9,420,376, respectively.

Revenue Recognition—The Company generates revenue primarily from the sale of refined products produced at the Company’s refinery and refined products purchased directly from outside sources. In general, the Company enters into spot and short-term agreements that stipulate the terms and conditions of the sales. Revenue is recorded as products are delivered to customers, which is the point at which title and risk of loss are transferred. Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the consolidated statements of operations.

The Company also engages in trading activities, whereby the Company enters into agreements to purchase and sell refined products with third parties. The Company acts as principle in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards of ownership. The Company records revenue for the gross amount of the sales transactions, and records cost of purchases as an operating expense in the accompanying consolidated financial statements.

 

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Excise tax, motor fuel tax, sales tax, and other taxes invoiced to customers and payable to government agencies are recorded on a net basis with the tax portion of a sales invoice directly credited to a liability account.

Comprehensive Income (Loss)—Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes unrealized gains and losses from available-for-sale securities.

Environmental Costs and Other Contingencies:

Environmental Costs—The Company records an undiscounted liability on the consolidated balance sheets as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of the liabilities are based on currently available facts, existing technology, and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience, and data released by the United States Environmental Protection Agency (“EPA”) or other organizations. The estimates are subject to revision in future periods based on actual costs or new circumstances.

Other Contingencies—The Company recognizes a liability for other contingencies when the Company has an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome can be estimated, the Company accrues a liability for that amount. Alternatively, where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

3. Long-Term Debt

 

     December 31, 2010     December 31, 2009  

Term loan—due November 2014

   $ 96,250,000      $ 107,250,000   

Finance obligation—due September 2029

     19,828,228        19,964,693   

Capital lease obligation—due September 2029

     30,804,621        31,213,642   

Airplane loan—due March 2014

     4,734,717        4,898,518   

Other notes—due February 2011

     5,412        32,824   

Less discount on term loan

     (7,364,382     (10,457,010
  

 

 

   

 

 

 

Total debt

     144,258,596        152,902,667   

Less obligations due in one year

     (14,582,463     (11,739,262
  

 

 

   

 

 

 

Long-term debt

   $ 129,676,133      $ 141,163,405   
  

 

 

   

 

 

 

Term Loan—GWEC, WRC, and the Holding Company, collectively, are a party to a secured five-year $110,000,000 discounted term loan facility (the “Term Loan”) dated November 13, 2009 (as amended) with a syndicate of financial institutions. Borrowings under the Term Loan accrue interest on floating rates based on LIBOR or the agent’s prime rate at the Company’s option. Borrowings are repayable quarterly starting December 31, 2009, with 10% of the principal payable in year’s one and two, 20% payable in year’s three and four, and 40% payable in year five. The last scheduled payment is September 30, 2014. At December 31, 2010, the Company had $96,250,000 outstanding.

Revolver—GWEC, WRC, and the Holding Company collectively, entered into a three-year $150,000,000 secured revolving credit facility (the “Revolver”) dated November 13, 2009 (as amended) with a syndicate of financial institutions. The Company can borrow and/or issue letters of credit, which in the aggregate, cannot exceed the lesser of the borrowing base or $150,000,000. The borrowing base is limited by the balances of cash, accounts receivable, inventory, exchange balances, and outstanding letters of credit for which no payable yet

 

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exists. The borrowing base was $150,000,000 at December 31, 2010. Borrowings under this facility accrue interest based on LIBOR or base rate options plus a margin based on the Company’s fixed charge coverage ratio. Borrowings are repayable at expiration of the revolving facility on November 12, 2012. There was no outstanding Revolver balance at December 31, 2010.

Letters of credit are primarily obtained by the Company for its routine purchases of crude oil. Letters of credit totaling $30,624,143 and $34,273,000 had been issued as of December 31, 2010 and 2009, respectively.

The Term Loan and Revolver are secured by substantially all of GWEC’s and WRC’s assets and are subject to various financial and nonfinancial covenants that limit distributions, dividends, acquisitions, capital expenditures, disposals and debt and require minimum debt service coverage, net worth, and working capital requirements. The Company was in compliance with its financial covenants and ratios at December 31, 2010.

Airplane Loan—GWEC has a $5,300,000 loan with a bank. Under the agreement, interest is payable at a fixed rate for the first three years and at a variable rate based on the 30-day LIBOR for the remaining four years. The loan is to be repaid over seven years with principal payments based on a 20-year amortization period and a balloon payment at the end of the seventh year in 2014. The loan is secured by the airplane. The outstanding balance at December 31, 2010 was $4,734,717.

Finance Obligation—On September 9, 2009, WRC sold its bulk terminal and loading facility for $20,000,000. WRC, in turn, agreed to lease back those same assets for 10 years with two five year renewal options. Under the terms of the lease agreement, WRC is required to support the operations of the terminal and loading facility at its own risk and GWEC has guaranteed WRC’s lease payments. Due to these various forms of continuing involvement, the transaction was recorded under the finance method of accounting. Accordingly, the value of the terminal and loading facility remain on the Company’s books and are continuing to be depreciated over their remaining useful lives. The proceeds received have been recorded as a finance obligation. The obligation is payable in monthly installments. The outstanding balance at December 31, 2010 was $19,828,228.

Capital Lease—On September 9, 2009, WRC entered into a sale-leaseback transaction where WRC sold a 49 mile pipeline for $32,000,000 and leased back the same pipeline for a term of 20 years. The transaction was recorded using sale-leaseback accounting. The gain of $30,741,039 is being deferred as an offset to the leased pipeline and is being amortized in proportion to the leased pipeline over the term of the lease. The lease is payable in monthly installments. The outstanding balance at December 31, 2010 was $30,804,621.

Other Notes—In February 2006, the Company entered into a financing agreement and a capital lease arrangement for office copiers which expire in February 2011. The obligations are payable in monthly installments. Amounts outstanding under these arrangements at December 31, 2010 were $5,412.

Letters of credit fees, bond fees, unused commitment fees, amortization of deferred financing costs, accretion of discount on debt, amortization of premium on interest rate cap, and interest from borrowings under the various agreements are included in interest expense in the accompanying consolidated statements of operations (net of amounts capitalized).

 

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The minimum remaining principal payments under the loan agreements and minimum lease payments under capital lease obligations are as follows:

 

Year Ending December 31,

  Term Loan     Airplane
Loan
    Commercial
& Other Notes
    Finance
Obligation
    Capital Lease     Total  

2011

  $ 13,750,000      $ 174,267      $ 5,412      $ 191,850      $ 4,380,000      $ 18,501,529   

2012

    22,000,000        185,403        —          253,518        4,392,000        26,830,921   

2013

    27,500,000        197,250        —          322,103        4,380,000        32,399,353   

2014

    33,000,000        4,177,797        —          398,302        4,380,000        41,956,099   

2015

    —          —          —          482,881        4,380,000        4,862,881   

Thereafter

    —          —          —          18,179,574        60,357,058        78,536,632   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total minimum lease payments

  $ 96,250,000      $ 4,734,717      $ 5,412      $ 19,828,228        82,269,058        203,087,415   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less amount representing executory costs

            (4,589,808     (4,589,808
         

 

 

   

 

 

 

Net minimum lease payments

            77,679,250        198,497,607   

Less amount representing interest

            (46,874,629     (46,874,629
         

 

 

   

 

 

 

Present value of net minimum lease payments

          $ 30,804,621      $ 151,622,978   
         

 

 

   

 

 

 

4. Tax Dividend Obligation To Parent

GWEC and its subsidiaries are S Corporations for income tax purposes. In general, as an S Corporation, GWEC and its subsidiaries are not taxable, and taxable income and deductions flow from GWEC and its subsidiaries to TGWC, where the income is taxed at the shareholder level. Prior to October 1, 2009, the Company reimbursed TGWC for the computed state and federal income taxes based on the Company’s net income and a combined rate of approximately 33%. On November 13, 2009, with the creation of the Holding Company, a new tax agreement (effective October 1, 2009) was entered into between the Holding Company, its subsidiaries, and TGWC. Pursuant to this agreement, GWEC reimburses the Holding Company for the computed state and federal income taxes based on GWEC’s net taxable income and a combined rate of 40%, that GWEC would pay if it determined its tax liability as a stand-alone C Corporation. These amounts are reflected as tax dividends declared in the consolidated statements of changes in shareholder’s equity. Each of GWEC’s subsidiaries reimburses GWEC on the same basis. When GWEC recognizes a net loss, such loss multiplied by 40% reduces its tax reimbursement liability in future years.

5. Employee Benefit Plans

The Company has two profit sharing plans (defined contribution plans), one covering certain nonunion employees and one covering union employees. The employees must meet eligibility requirements as to age and length of service. Contributions to the plans are determined annually by the Company. Contributions of $1,643,600, $1,486,246 and $1,357,075 were expensed for the years ended December 31, 2010, 2009 and 2008 respectively.

6. Concentrations

Substantially all of the Company’s accounts receivable at December 31, 2010 and 2009 results from the sale of refined products to companies in the retail and wholesale distribution market. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic and other conditions. Such receivables are generally not collateralized. However, the Company performs credit evaluations on its customers to minimize the exposure to credit risk. No single customer accounted for more than 10% of product sales for the years ended December 31, 2010, 2009 and 2008, respectively. No single customer accounted for more than 10% of gross accounts receivable at December 31, 2010 and 2009, respectively.

 

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In March 2010 and 2009, the Company was awarded contracts to sell approximately 58,000,000 gallons, per contract year, of jet fuel to the United States Defense Energy Support Center (“DESC”) for the period April 1 through March 31 of the following year, plus a 30-day carryover which gives the DESC the option to take deliveries for one month after the stated contract period. Pricing is variable, calculated based on market prices, as specified in the contract. For the years ended December 31, 2010, 2009 and 2008, product sales to this customer approximated 5%, 5% and 6%, respectively, of total operating revenue.

In addition, substantially all of the Company’s raw materials purchased for refinery production and refined products purchased for resale are from companies in the oil and gas exploration and production industry in the United States. This concentration of suppliers may impact the Company’s overall costs and/or profitability, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic and other conditions. For the years ended December 31, 2010, 2009 and 2008, three vendors accounted for 41%, 47% and 37%, respectively, of total raw material and refined purchases.

Approximately 51% of the Company’s labor force is covered by a collective bargaining agreement that is subject to review and renewal on a regular basis. The current collective bargaining agreement is due to expire in June 2012.

7. Related-Party Transactions

GWEC has an agreement with an affiliate, as amended and renewed in May 2008, to sublease a hangar for the Company aircraft. Terms of the sublease provide for annual rentals of $87,000 until June 30, 2011.

On a monthly basis, the Company charges certain general and administrative support costs to its affiliates. At December 31, 2010 and 2009, the affiliated accounts receivable balance was $174,543 and $163,877, respectively.

GWEC entered into a promissory note in February 2010 with TGWC, whereby GWEC promised to pay TGWC the principal sum of $10,000,000 or such lesser amount the borrower shall borrow from the lender. Interest on the unpaid principal balance is computed daily based on the prime rate. All amounts borrowed, together with interest, are to be paid no later than ten business days after the funds are advanced. The note is due on January 31, 2012. There was no outstanding balance under the note at December 31, 2010 and 2009, respectively.

8. Commitments And Contingencies

Fire Contingencies and Insurance Reimbursement

Alky Fire

On May 12, 2006, a fire took place at the Company’s refinery in Wynnewood, Oklahoma. The fire occurred in an alkylation unit, which is used in the production of high octane, low sulfur gasoline blend stocks. The fire resulted in damage to the alkylation unit and surrounding equipment, wiring, and instrumentation systems.

The Company is insured for losses related to its refinery property and business interruption. At the time of the fire, the Company’s refinery property insurance coverage was subject to a $1,000,000 per claim deductible and the business interruption insurance coverage was subject to a 45-day business interruption waiting period with a $1,000,000 minimum and a $10,000,000 maximum deductible.

In the years ended December 31, 2009 and 2008, the Company expensed $40,324 and $997,886, to fire-related loss to cover professional services fees, penalties, and other fire-related costs. Through December 31, 2009, the Company had incurred testing, refurbishment, and replacement costs of $33,473,402, which has been capitalized in property, plant and equipment, net. Initially, in 2006, the Company recorded an asset impairment charge of $649,478 to fire-related loss.

 

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In addition to the property damage, through December 31, 2009, the Company also sustained business interruption losses associated with the fire of approximately $51,000,000, net of a deductible of $10,000,000. These losses include lost income related to the loss of use of the alkylation unit, the extra transportation costs incurred for transporting product from the unit while it is out of service, and the reduced volumes of hydrocarbons that could be processed. These costs have been expensed as incurred.

As a result of the property damage and business interruption losses associated with the fire, the Company has submitted, net of a deductible of $11,000,000, approximately $81,000,000 in claims to its insurance carriers under its insurance policies. As of December 31, 2007, the insurance providers approved and the Company collected $42,832,697 of these costs, $25,179,697 to cover business interruption and $17,653,000 for property damage. Of the total amount recovered, $2,832,697 was recorded during the year ended December 31, 2007, $2,653,000 as fire-related gain and $179,697 as a reduction to operating expense to cover business interruption. During 2006, the Company recorded $15,000,000 as fire-related gain and $25,000,000 as a reduction to operating expense for business interruption.

In the fourth quarter of 2007, the Company initiated legal action against its insurance carriers as a result of the insurance carrier’s refusal to honor their insurance coverage obligation to pay the remaining balance on the claim. The Company settled with the insurance carriers in January 2009 for $21,167,253. As a result, in December 2008 the Company recognized $2,525,000 as fire-related gain and $18,642,253 as a reduction to operating expense to cover business interruption.

Lightning Fire

On April 27, 2007, the Company’s refinery in Wynnewood, Oklahoma was shut down after lightning caused a fire in a product storage tank, which then spread to a second tank in the same dike. The Company lost both tanks and the products in the tanks. The Company recorded an insurance recovery gain of $6,000,000, a $5,151,740 expense from lost inventory, and fire response and clean up expenditures of $270,957. Through December 31, 2009, the Company also incurred testing, refurbishment, and replacement costs of $3,776,613, which has been capitalized as property, plant, and equipment, net.

For the year ended December 31, 2009, the Company recognized a fire-related expense of $638 for professional service fees. For the year ended December 31, 2008, the Company recognized a net fire-related gain of $1,261,102. The Company recognized an insurance recovery gain of $1,283,712 and professional service fees of $22,610.

As of December 31, 2009, the insurance providers had approved $7,283,712 and the Company has collected $6,980,377 of these costs. At December 31, 2009, the Company’s receivable for recoveries from insurance carriers was $303,335.

Legal Matters—In the ordinary course of business, the Company is a party to various other legal matters. In the opinion of management, none of these matters, either individually or in the aggregate, will have a material adverse effect on the Company’s financial condition, liquidity, or results of operations.

Health, Safety, and Environmental Matters—The Company is subject to certain environmental, safety, and other regulations primarily administered by the EPA and various state agencies. In addition, the EPA requires that the Company provide assurance of its financial wherewithal regarding certain future closure costs of the facility. Except as discussed below, management of the Company believes it has complied with all material aspects associated with these regulations.

By letter dated October 26, 2005, WRC received a “Finding of Violation” (“FOV”) from the EPA, Region 6, purportedly pursuant to Section 113 of the Federal Clean Air Act. The FOV alleged certain violations of New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. WRC has provided the EPA with explanatory and exculpatory information in response to the EPA FOV. Based on

 

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Index to Financial Statements

discussions with the EPA, the Company has determined that the settlement will include both corrective actions and payment of civil penalties, which could be material. As of December 31, 2010, the Company has $1,000,000 accrued to cover the penalties. Actual penalties could exceed this amount, however, management does not anticipate that the ultimate outcome of this matter will have a material adverse impact on the Company’s financial position, liquidity, or results of operations.

The Federal Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products manufactured in order to limit the emissions associated with their final use. In December 1999, the EPA promulgated national regulations limiting the amount of sulfur to be allowed in gasoline at future dates. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. The new regulations required the phase-in of gasoline sulfur standards beginning in 2004, with the final reduction to the sulfur content of gasoline to an annual average level of 30 parts-per-million (“ppm”), and a per gallon maximum of 80 ppm to be completed by June 2006. As a small refiner, WRC became a party to the Waiver and Compliance Plan with the EPA that extended the implementation deadline for low sulfur gasoline to 2011. In return for the extension, WRC was required to produce 95% of the diesel fuel at the refinery with a sulfur content of 15 ppm or less starting June 1, 2006. WRC has complied with this requirement in 2010 and anticipates meeting the new regulations effective on January 1, 2011.

Other Matters—TGWC entered into a 10-year lease agreement extension for office space in June 2003. The Company pays all rent and occupancy costs in exchange for its use of the office space. The Company has guaranteed the performance of TGWC’s obligations, under which the Company could be legally obligated to pay annual rent, as scheduled below, and annual occupancy costs of $356,918 with provisions for escalation based on actual expenses. The monthly rent is expensed on a straight-line basis over the term of the office lease. Rent expense, including occupancy costs, for the years ended December 31, 2010, 2009 and 2008 was $898,385, $1,025,689 and $949,997, respectively.

The aggregate minimum rental commitments under noncancelable leases for the periods shown at December 31, 2010, are as follows:

 

Year

   Annual Rent  

2011

   $ 577,297   

2012

     547,102   

2013

     273,551   
  

 

 

 
   $ 1,397,950   
  

 

 

 

The Company currently has one throughput and deficiency agreement that expires in 2020. Under the terms of the agreement, the Company is obligated to pay a tariff fee on a minimum daily volume of crude or else pay for any deficiencies. The fees paid under throughput and deficiency obligations for the years ended December 31, 2010 and 2009 were $6,939,940 and $10,166,013, respectively. At December 31, 2010, the minimum commitments under the throughput and deficiency agreement are as follows:

 

Year

   Transportation
Obligation
 

2011

   $ 3,942,000   

2012

     3,952,800   

2013

     3,942,000   

2014

     3,942,000   

2015

     3,942,000   

Thereafter

     17,074,800   
  

 

 

 
   $ 36,795,600   
  

 

 

 

******

 

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Annex A

 

 

 

 

FORM OF

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

CVR REFINING, LP

 

 

 

 

 

 


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

          Page  
ARTICLE I   
DEFINITIONS   

Section 1.1

   Definitions      A-1   

Section 1.2

   Construction      A-10   
ARTICLE II   
ORGANIZATION   

Section 2.1

   Formation      A-10   

Section 2.2

   Name      A-10   

Section 2.3

   Registered Office; Registered Agent; Principal Office; Other Offices      A-11   

Section 2.4

   Purpose and Business      A-11   

Section 2.5

   Powers      A-11   

Section 2.6

   Term      A-11   

Section 2.7

   Title to Partnership Assets      A-11   
ARTICLE III   
RIGHTS OF LIMITED PARTNERS   

Section 3.1

   Limitation of Liability      A-12   

Section 3.2

   Management of Business      A-12   

Section 3.3

   Outside Activities of the Limited Partners      A-12   

Section 3.4

   Rights of Limited Partners      A-12   
ARTICLE IV   
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;   
REDEMPTION OF PARTNERSHIP INTERESTS   

Section 4.1

   Certificates      A-13   

Section 4.2

   Mutilated, Destroyed, Lost or Stolen Certificates      A-13   

Section 4.3

   Record Holders      A-14   

Section 4.4

   Transfer Generally      A-14   

Section 4.5

   Registration and Transfer of Limited Partner Interests      A-14   

Section 4.6

   Transfer of the General Partner Interest      A-15   

Section 4.7

   Restrictions on Transfers      A-15   

Section 4.8

   Eligibility Certificates; Ineligible Holders      A-16   

Section 4.9

   Redemption of Partnership Interests of Ineligible Holders      A-17   
ARTICLE V   
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS   

Section 5.1

   Contributions by the General Partner and its Affiliates      A-18   

Section 5.2

   Contributions by Initial Limited Partners      A-18   

Section 5.3

   Interest and Withdrawal      A-18   

Section 5.4

   Capital Accounts      A-18   

Section 5.5

   Issuances of Additional Partnership Interests and Derivative Instruments      A-20   

Section 5.6

   Preemptive Right      A-21   

Section 5.7

   Splits and Combinations      A-21   

Section 5.8

   Fully Paid and Non-Assessable Nature of Limited Partner Interests      A-22   

 

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Index to Financial Statements
          Page  
ARTICLE VI   
ALLOCATIONS AND DISTRIBUTIONS   

Section 6.1

   Allocations for Capital Account Purposes      A-22   

Section 6.2

   Allocations for Tax Purposes      A-25   

Section 6.3

   Distributions to Record Holders      A-26   
ARTICLE VII   
MANAGEMENT AND OPERATION OF BUSINESS   

Section 7.1

   Management      A-26   

Section 7.2

   Replacement of Fiduciary Duties      A-28   

Section 7.3

   Certificate of Limited Partnership      A-28   

Section 7.4

   Restrictions on the General Partner’s Authority      A-28   

Section 7.5

   Reimbursement of the General Partner      A-28   

Section 7.6

   Outside Activities      A-29   

Section 7.7

   Indemnification      A-30   

Section 7.8

   Liability of Indemnitees      A-31   

Section 7.9

   Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties      A-32   

Section 7.10

   Other Matters Concerning the General Partner      A-33   

Section 7.11

   Purchase or Sale of Partnership Interests      A-34   

Section 7.12

   Registration Rights of the General Partner and its Affiliates      A-34   

Section 7.13

   Reliance by Third Parties      A-36   
ARTICLE VIII   
BOOKS, RECORDS, ACCOUNTING AND REPORTS   

Section 8.1

   Records and Accounting      A-36   

Section 8.2

   Fiscal Year      A-36   

Section 8.3

   Reports      A-36   
ARTICLE IX   
TAX MATTERS   

Section 9.1

   Tax Returns and Information      A-37   

Section 9.2

   Tax Elections      A-37   

Section 9.3

   Tax Controversies      A-37   

Section 9.4

   Withholding      A-37   
ARTICLE X   
ADMISSION OF PARTNERS   

Section 10.1

   Admission of Limited Partners      A-38   

Section 10.2

   Admission of Successor General Partner      A-38   

Section 10.3

   Amendment of Agreement and Certificate of Limited Partnership      A-38   
ARTICLE XI       
WITHDRAWAL OR REMOVAL OF PARTNERS   

Section 11.1

   Withdrawal of the General Partner      A-39   

Section 11.2

   Removal of the General Partner      A-40   

Section 11.3

   Interest of Departing General Partner and Successor General Partner      A-40   

Section 11.4

   Withdrawal of Limited Partners      A-41   
ARTICLE XII   
DISSOLUTION AND LIQUIDATION   

Section 12.1

   Dissolution      A-41   

Section 12.2

   Continuation of the Business of the Partnership After Dissolution      A-42   

 

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          Page  

Section 12.3

   Liquidator      A-42   

Section 12.4

   Liquidation      A-42   

Section 12.5

   Cancellation of Certificate of Limited Partnership      A-43   

Section 12.6

   Return of Contributions      A-43   

Section 12.7

   Waiver of Partition      A-43   

Section 12.8

   Capital Account Restoration      A-43   
ARTICLE XIII   
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE   

Section 13.1

   Amendments to be Adopted Solely by the General Partner      A-43   

Section 13.2

   Amendment Procedures      A-44   

Section 13.3

   Amendment Requirements      A-45   

Section 13.4

   Special Meetings      A-45   

Section 13.5

   Notice of a Meeting      A-46   

Section 13.6

   Record Date      A-46   

Section 13.7

   Adjournment      A-46   

Section 13.8

   Waiver of Notice; Approval of Meeting; Approval of Minutes      A-46   

Section 13.9

   Quorum and Voting      A-46   

Section 13.10

   Conduct of a Meeting      A-47   

Section 13.11

   Action Without a Meeting      A-47   

Section 13.12

   Right to Vote and Related Matters      A-48   
ARTICLE XIV   
MERGER   

Section 14.1

   Authority      A-48   

Section 14.2

   Procedure for Merger or Consolidation      A-48   

Section 14.3

   Approval by Partners of Merger or Consolidation      A-49   

Section 14.4

   Certificate of Merger      A-50   

Section 14.5

   Amendment of Partnership Agreement      A-50   

Section 14.6

   Effect of Merger      A-50   
ARTICLE XV   
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS   

Section 15.1

   Right to Acquire Limited Partner Interests      A-50   
ARTICLE XVI   
GENERAL PROVISIONS   

Section 16.1

   Addresses and Notices      A-51   

Section 16.2

   Further Action      A-52   

Section 16.3

   Binding Effect      A-52   

Section 16.4

   Integration      A-52   

Section 16.5

   Creditors      A-52   

Section 16.6

   Waiver      A-52   

Section 16.7

   Counterparts      A-52   

Section 16.8

   Applicable Law; Forum, Venue and Jurisdiction      A-53   

Section 16.9

   Invalidity of Provisions      A-53   

Section 16.10

   Consent of Partners      A-53   

Section 16.11

   Facsimile Signatures      A-54   

Section 16.12

   Third Party Beneficiaries      A-54   

 

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Index to Financial Statements

FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED

PARTNERSHIP OF CVR REFINING, LP

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF CVR REFINING, LP, dated as of                     , 201    , is entered into by and among CVR Refining GP, LLC, a Delaware limited liability company, as the General Partner, and CVR Refining Holdings, LLC, a Delaware limited liability company, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Sections 6.1(b)(i) or 6.1(b)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Sections 5.4(d)(i) or 5.4(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries Controls, is Controlled by or is under common Control with, the Person in question.

Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

Agreed Value” of any Contributed Property means the fair market value of such property at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.4(d) in both cases as determined by the General Partner.

Agreement” means this First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, as it may be amended, supplemented or restated from time to time.

Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.


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Index to Financial Statements

Bad Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such Person, board or committee reached such determination, or engaged in or failed to engage in such act or omission, with the belief that such determination, action or omission was adverse to the interest of the Partnership.

Board of Directors” means the board of directors of the General Partner.

Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America, the State of Kansas, the State of Oklahoma or the State of Texas shall not be regarded as a Business Day.

Capital Account” means the capital account maintained for a Partner pursuant to Section 5.4. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d), and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

Certificate” means a certificate in such form (including global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.3, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

claim” (as used in Section 7.12(c)) has the meaning assigned to such term in Section 7.12(c).

Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

 

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Index to Financial Statements

Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

Code” means the U.S. Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

Combined Interest” has the meaning assigned to such term in Section 11.3(a).

Commission” means the United States Securities and Exchange Commission.

Common Unit” means a Unit representing, when outstanding, a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement.

Conflicts Committee” means a committee of the Board of Directors composed entirely of one or more directors who are not (a) officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner or (c) holders of any ownership interest in the General Partner or any of its Affiliates, including any Group Member, other than Common Units and other awards that are granted to such director under the Long Term Incentive Plan and who also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by (i) the National Securities Exchange on which any class of Partnership Interests are listed or admitted to trading or (ii) if no class of Partnership Interests is so listed or traded, by the New York Stock Exchange, Inc.

Contributed Property” means each property, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of December 31, 2012, among the Organizational Limited Partner, CVR Refining Holdings Sub, LLC and the Partnership, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

Contribution Date” means the date of the Contribution Agreement, on which the Organizational Limited Partner contributed all of its equity interests in CVR Refining, LLC to the Partnership.

Control” or “control” (including the terms “controlled” and “controlling”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

 

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Index to Financial Statements

Credit Agreement” means the Credit Agreement, dated as of                     , 20    , among Coffeyville Resources, LLC, as Lender, and CVR Refining, LLC, as borrower, as such agreement may be amended, modified, supplemented, replaced, refinanced or otherwise restructured from time to time, including any refinancing, restructuring or replacement by one or more other credit agreements, indentures, purchase agreements or other agreements, whether or not the amount covered thereby is increased or decreased, and with the same or different counterparties.

Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(b)(xi).

Current Market Price” means, in respect of any class of Partnership Interests, as of the date of determination, the average of the daily Closing Prices per Partnership Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

Deferred Issuance and Distribution” means both (a) the issuance by the Partnership of a number of additional Common Units that is equal to the excess, if any, of (x)          over (y) the aggregate number, if any, of Common Units actually purchased by and issued to the Underwriters pursuant to the Over-Allotment Option on the Option Closing Date(s), and (b) a distribution of cash in an amount equal to the total amount of cash contributed by the Underwriters to the Partnership on or in connection with any Option Closing Date with respect to Common Units issued by the Partnership upon the applicable exercise of the Over-Allotment Option, if any.

Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Sections 11.1 or 11.2.

Derivative Instruments” means options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative instruments relating to, convertible into or exchangeable for Partnership Interests.

Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

Eligibility Certificate” has the meaning assigned to such term in Section 4.8(b).

Eligibility Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

Eligible Holder” means a Person that satisfies the eligibility requirements established by the General Partner for Partners pursuant to Section 4.8.

Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

General Partner” means CVR Refining GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as the general partner of the Partnership, in their capacity as the general partner of the Partnership.

General Partner Interest” means the non-economic management interest of the General Partner in the Partnership (in its capacity as general partner and without reference to any Limited Partner Interest held by it), which includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not have any rights to ownership or profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership.

 

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Index to Financial Statements

Good Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such determination, action or omission was not taken in Bad Faith.

Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

Group Member” means a member of the Partnership Group.

Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

Indemnified Persons” has the meaning assigned to such term in Section 7.12(c).

Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Affiliate of any Person referred to in clause (a) or (b) (a “Covered Affiliate”), (d) any Person who is or was a director, officer, fiduciary, trustee, manager or managing member of any Group Member, the General Partner, any Departing General Partner or Covered Affiliate, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner as a director, officer, fiduciary, trustee, manager or managing member of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who Controls or has previously Controlled, directly or indirectly, the General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group’s business and affairs.

Ineligible Holder” has the meaning assigned to such term in Section 4.8(c).

Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement, including the offering and any sale of Common Units pursuant to the Over-Allotment Option.

Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case in such Person’s capacity as a limited partner of the Partnership.

 

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Index to Financial Statements

Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units or other Partnership Interests or a combination thereof or interest therein (but excluding Derivative Instruments), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement.

Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the Partners have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

Long Term Incentive Plan” means the CVR Partners, LP 2011 Long-Term Incentive Plan, as it may be amended, restated or modified from time to time, or any equity compensation plan successor thereto.

Merger Agreement” has the meaning assigned to such term in Section 14.1.

National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) of the Securities Exchange Act (or successor to such Section)) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain for such taxable period over the Partnership’s items of loss and deduction for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) but shall not include any items specially allocated under Section 6.1(b).

Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction for such taxable period over the Partnership’s items of income and gain for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) but shall not include any items specially allocated under Section 6.1(b).

Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

 

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Index to Financial Statements

Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

Organizational Limited Partner” means CVR Refining Holdings, LLC in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates, including CVR Refining Holdings, LLC, Coffeyville Resources, LLC and CVR Energy, Inc.) beneficially owns 20% or more of the Outstanding Limited Partner Interests of any class then Outstanding, none of the Limited Partner Interests owned by such Person or Group shall be entitled to be voted on any matter or considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Limited Partner Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation on voting of Partnership Interests shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Limited Partner Interests of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Limited Partner Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Limited Partner Interests issued by the Partnership provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

Partner Nonrecourse Debt” has the meaning given to such term in Treasury Regulation Section 1.704-2(b)(4).

Partner Nonrecourse Debt Minimum Gain” has the meaning given to such term in Treasury Regulation Section 1.704-2(i)(2).

Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i)(1), are attributable to a Partner Nonrecourse Debt.

Partners” means the General Partner and the Limited Partners.

Partnership” means CVR Refining, LP, a Delaware limited partnership.

Partnership Group” means the Partnership and its Subsidiaries.

 

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Partnership Interest” means an interest in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude Derivative Instruments.

Partnership Minimum Gain” means the amount of “partnership minimum gain” determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

Percentage Interest” means as of any date of determination (a) as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage or percentages applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder, by (B) the total number of Outstanding Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.5, the percentage established as a part of such issuance. The Percentage Interest with respect to the General Partner Interest shall at all times be zero.

Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests and (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests.

Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership.

Rate Eligibility Trigger” has the meaning assigned to such term in Section 4.8(a)(i).

Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

Record Holder” means (a) with respect to Partnership Interests of any class for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

Registration Rights Agreement” means that certain Registration Rights Agreement, dated as of                     , 201    , among the Organizational Limited Partner, CVR Refining Holdings Sub, LLC and the Partnership.

 

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Index to Financial Statements

Registration Statement” means the Registration Statement on Form S-1 (File No. 333-184200) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering, including any related registration statement filed pursuant to Rule 462(b) under the Securities Act.

Reorganization Agreement” means that certain Reorganization Agreement, dated as of                     , 2013, among the Organizational Limited Partner, CVR Refining Holdings Sub, LLC, the General Partner and the Partnership.

Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Sections 6.1(b)(i), 6.1(b)(ii), 6.1(b)(iv), 6.1(b)(v), 6.1(b)(vi), 6.1(b)(vii) or 6.1(b)(ix).

Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

Special Approval” means approval by a majority of the members of the Conflicts Committee.

Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, directly or by one or more Subsidiaries of such Person, or a combination thereof, controls such partnership, directly or indirectly, at the date of determination or (c) any other Person in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b)(ii).

Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests is listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

transfer” has the meaning assigned to such term in Section 4.4(a).

Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

Underwriting Agreement” means that certain Underwriting Agreement dated                     , 201    , by and among the representatives of the Underwriters, the Partnership, and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units.

 

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Unit Majority” means at least a majority of the Outstanding Common Units.

Unitholders” means the holders of Units.

Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

Unrestricted Person” means each Indemnitee, each Partner and each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner and any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement.

U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation. The General Partner and the Organizational Limited Partner previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act. The General Partner and the Organizational Limited Partner hereby amend and restate the original Agreement of Limited Partnership of the Partnership in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties, liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.

Section 2.2 Name. The name of the Partnership shall be “CVR Refining, LP”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” the letters “LP,” or “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Partners of such change in the next regular communication to the Partners.

 

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Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479 or such other place as the General Partner may from time to time designate by notice to the Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479 or such other place as the General Partner may from time to time designate by notice to the Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

 

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ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.6, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have any business interests and engage in any business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law (other than Section 17-305(a) of the Delaware Act, the obligations of which are expressly replaced in their entirety by the provisions below), and except as limited by Section 3.4(b) and (c), each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) shall be satisfied to the extent the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act);

(ii) a current list of the name and last known business, residence or mailing address of each Record Holder;

(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed; and

(iv) such other information regarding the affairs of the Partnership as the General Partner determines is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

 

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(c) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person.

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner. No Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct, to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Partner fails to notify the General Partner within a reasonable period of time after such Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

 

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(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, grant of security interest, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise, or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise (but not the pledge, grant of security interest, encumbrance, hypothecation or mortgage), including any transfer upon foreclosure or other exercise of remedies of any pledge, security interest, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in such Partner and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent

 

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shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or amendment of this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

Section 4.6 Transfer of the General Partner Interest.

(a) The General Partner may at its option transfer all or any part of its General Partner Interest without Unitholder approval.

(b) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable U.S. federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if the General Partner determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) Nothing contained in this Agreement (other than Section 4.7(a)), shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

 

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Section 4.8 Eligibility Certificates; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that:

(i) the Partnership’s status as other than as an association taxable as a corporation for U.S. federal income tax purposes or the failure of the Partnership to be subject to an entity-level tax for U.S. federal, state or local income tax purposes, coupled with the tax status (or lack of proof of the U.S. federal income tax status) of one or more Partners, has or will reasonably likely have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership (a “Rate Eligibility Trigger”); or

(ii) any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Partner (a “Citizenship Eligibility Trigger”);

then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to (x) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Partners whose U.S. federal income tax status does not or would not have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status (or, if the General Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) of the Partner as the General Partner determines to be necessary to establish and those Partners whose status as a Partner does not or would not subject any Group Member to a significant risk of cancellation or forfeiture of any of its properties or interests therein.

(b) Such amendments may include provisions requiring all Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Partner (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its’ beneficial owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Partner is not an Eligible Holder (such a Partner, an “Ineligible Holder”), the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner shall be substituted for all Limited Partners that are Ineligible Holders as the Partner in respect of the Ineligible Holder’s Partnership Interests.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Partnership Interest (representing his right to receive his share of such distribution in kind).

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such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Partner in respect of such Ineligible Holder’s Partnership Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Partner fails to furnish an Eligibility Certification or other information requested within a reasonable period of time specified in amendments adopted pursuant to Section 4.8, or if upon receipt of such Eligibility Certification or other information the General Partner determines, with the advice of counsel, that a Partner is not an Eligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Partnership Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, as applicable, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 8% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Partnership Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

 

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ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Contributions by the General Partner and its Affiliates.

(a) In connection with the formation of the Partnership under the Delaware Act, the General Partner was admitted as the sole General Partner of the Partnership and the Organizational Limited Partner agreed to make an initial Capital Contribution to the Partnership in the amount of $1,000 and was admitted as the Organizational Limited Partner of the Partnership. As of the Contribution Date, and effective with the admission of CVR Refining Holdings Sub, LLC as a Limited Partner to the Partnership, the initial cash Capital Contribution of the Organizational Limited Partner was refunded. One-hundred percent of any interest or other profit that may have resulted from the investment or other use of such initial cash Capital Contribution will be allocated and distributed to the Organizational Limited Partner.

(b) On the Contribution Date and pursuant to the Contribution Agreement, the Organizational Limited Partner contributed to the Partnership, as a Capital Contribution, 100% of its equity interests in CVR Refining, LLC to the Partnership. The Organizational Limited Partner retained the right to receive reimbursement for certain capital expenditures attributable to the assets of CVR Refining, LLC and its subsidiaries incurred within the two-year period prior to the Contribution Date pursuant to Section 5.5(c) hereof and Section 2.02(b) of the Registration Rights Agreement.

(c) On the date hereof and pursuant to the Reorganization Agreement:

(i) the Organizational Limited Partner’s 99.99% limited partner and CVR Refining Holdings Sub LLC’s 0.01% limited partner interest were recharacterized as 124,587,540 Common Units and 12,460 Common Units, respectively;

(ii) the Partnership distributed to the Organizational Limited Partner the right to receive the Deferred Issuance and Distribution.

Section 5.2 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

Section 5.3 Interest and Withdrawal. No interest on Capital Contributions shall be paid by the Partnership. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Partnership may be considered as the withdrawal or return of its Capital Contribution by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.4 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the

 

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rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.4, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership or is disregarded for U.S. federal income tax purposes and (y) any other entity that is classified as a partnership or is disregarded for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined (A) under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for U.S. federal income tax purposes pursuant to Section 50(c)(1) or 50(c)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the taxable period such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 50(c)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

 

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(vii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d)(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), upon an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s (and its Affiliates’) Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may determine that it is appropriate to first determine an aggregate value for the Partnership, based on the current trading price of the Common Units, taking fully into account the fair market value of the Partnership Interests of all Partners at such time, and then allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines is appropriate).

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for the purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Partnership Interests and Derivative Instruments.

(a) The Partnership may issue additional Partnership Interests and Derivative Instruments for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Partners.

 

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(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior or junior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may, or shall be required to, redeem the Partnership Interest (including sinking fund provisions); (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) Subject to, and in accordance with, the terms of the Registration Rights Agreement, upon request of the Organizational Limited Partner, the Partnership will undertake an offering of additional Common Units, and will use the proceeds thereof (net of underwriting discounts and commissions) to redeem an equal number of Common Units from the limited partner in full or partial satisfaction of the Organizational Limited Partner’s right to reimbursement pursuant to Section 1.1 of the Contribution Agreement.

(d) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Instruments pursuant to this Section 5.5, (ii) the conversion of the General Partner’s (and its Affiliates’) Combined Interest to Common Units pursuant to the terms of this Agreement, (iii) reflecting the admission of such additional Partners in the books and records of the Partnership as the Record Holder of such Partnership Interests, and (iv) all additional issuances of Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or in connection with the conversion of the General Partner’s (and its Affiliates’) Combined Interest into Common Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(e) No fractional Units shall be issued by the Partnership.

Section 5.6 Preemptive Right. Except as provided in this Section 5.6 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.

Section 5.7 Splits and Combinations.

(a) Subject to Section 5.7(d), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactively to the beginning of the Partnership.

 

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(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision, combination or reorganization. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision, or combination, the Partnership may issue Certificates to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of any such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Partnership Interests. If a distribution, subdivision, combination or reorganization of Partnership Interests would result in the issuance of fractional Units but for the provisions of Section 5.5(d) and this Section 5.7(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.8 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-607 or 17-804 of the Delaware Act.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction and credit (computed in accordance with Section 5.4(b)) for each taxable period shall be allocated among the Partners as provided herein below.

(a) Net Income and Net Loss. After giving effect to the special allocations set forth in Section 6.1(b), Net Income and Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income and Net Loss for such taxable period shall be allocated 100% to all Unitholders, Pro Rata.

(b) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other

 

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allocations pursuant to this Section 6.1(b) with respect to such taxable period (other than an allocation pursuant to Sections 6.1(b)(vi) and 6.1(b)(vii)). This Section 6.1(b)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(b)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(b), other than Section 6.1(b)(i) and other than an allocation pursuant to Sections 6.1(b)(vi) and 6.1(b)(vii), with respect to such taxable period. This Section 6.1(b)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit, each Unitholder receiving such greater cash or property distribution shall be allocated gross income in an amount equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution with respect to the Unit receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(b)(iv) were not in this Agreement.

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as so adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(b)(iv) and this Section 6.1(b)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners, Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

 

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(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss. This Section 6.1(b)(vii) is intended to comply with Treasury Regulations Section 1.704-2(i)(1) and shall be interpreted consistently therewith.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners, Pro Rata.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity; Changes in Law. For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss or deduction, including Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(b)(x) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. In exercising its discretion under this Section 6.1(b)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(b)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(b)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(b)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

 

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Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(b)(x)); provided that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Units, so long as such conventions would not have a material adverse effect on the Limited Partners or Record Holders of any class or classes of Limited Partner Interests.

(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(f) Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Closing Date occurs shall be allocated to the Partners who are issued Units as a result of the transactions contemplated by the Reorganization Agreement and the Underwriting Agreement; and provided, further, that each item of Partnership income, gain, loss and deduction for the period beginning on the Contribution Date and ending the date immediately before the Closing Date shall be allocated to the Partners holding Units on the date immediately before the Closing Date; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction, as determined by the General Partner, shall be allocated to

 

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the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of the month in which such item is recognized for U.S. federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(g) Allocations that would otherwise be made to a Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Distributions to Record Holders.

(a) The Board of Directors may adopt a cash distribution policy, which it may change from time to time without amendment to this Agreement.

(b) The Partnership will make distributions, if any, to Unitholders Pro Rata.

(c) All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.

(d) Notwithstanding Section 6.3(b), in the event of the dissolution and liquidation of the Partnership, cash shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(e) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner and no other Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted to a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

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(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject however to any prior approval that may be required by Section 7.4 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “chief executive officer,” “president,” “chief financial officer,” “chief operating officer,” “general counsel,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Partnership Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval required under Section 4.7);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Instruments;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member; and

(xv) the entering into of agreements with any of its Affiliates, including any agreements to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Limited Partners and each other Person who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Credit Agreement and the other agreements described in or filed as exhibits to the

 

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Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Replacement of Fiduciary Duties. Notwithstanding any other provision of this Agreement, to the extent that, at law or in equity, the General Partner or any other Indemnitee would have duties (including fiduciary duties) to the Partnership, to another Partner, to any person who acquires an interest in a Partnership Interest or to another Person that is a party to this Agreement or is otherwise bound by this Agreement, all such duties (including fiduciary duties) are hereby eliminated, to the fullest extent permitted by law, and replaced with the duties expressly set forth herein. The elimination of duties (including fiduciary duties) and replacement thereof with the duties expressly set forth herein are approved by the Partnership, all Partners, each other Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement.

Section 7.3 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Partner.

Section 7.4 Restrictions on the General Partner’s Authority. Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.5 Reimbursement of the General Partner.

(a) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses reasonably allocable to

 

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the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.5 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(b) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

(c) The General Partner, without the approval of the other Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees and directors of the General Partner or its Affiliates, any Group Member or their Affiliates, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any employees or directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.5(b). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.5(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.5(d).

Section 7.6 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member, (C) the guarantee of, and mortgage, pledge or encumbrance of any or all of its assets in connection with, any indebtedness of any Affiliate of the General Partner or (D) the direct or indirect provision of management, advisory, and administrative services to its Affiliates or to other Persons.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner.

(c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership shall have any duty to

 

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communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, any Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires such opportunity for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.

(d) Subject to the terms of Section 7.6(a), Section 7.6(b) and Section 7.6(c), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.6 is hereby approved by the Partnership and all Partners, and (ii) it shall be deemed not to be a breach of any fiduciary duty or any other duty or obligation of any type whatsoever of the General Partner or of any other Unrestricted Person for the Unrestricted Person (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(e) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise expressly provided in Section 7.11 of this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Interests acquired by them.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity on behalf of or for the benefit of the Partnership; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an

 

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Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement. In addition, the Partnership may enter into additional indemnification agreements with any Indemnitee.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by an Indemnitee with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Limitation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, any Group Member Agreement, or under the Delaware Act or any other law, rule or regulation or at equity, no Indemnitee shall be liable for monetary damages or otherwise to the Partnership, the Partners or any other Persons who have acquired interests in the Partnership Interests, for losses sustained or liabilities incurred, of any kind or character, as a result of its or any of any other Indemnitee’s determinations, act(s) or omission(s) in their capacities as Indemnitees; provided however, that an Indemnitee shall be liable for losses or liabilities sustained or incurred by the Partnership, the Partners or any other Persons who have acquired interests in the Partnership Interests, if it is determined by a final and non-appealable judgment entered by a court of competent jurisdiction that such losses or liabilities were the result of the conduct of that Indemnitee 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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(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner if such appointment was not made in Bad Faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Whenever the General Partner, acting in its capacity as the general partner of the Partnership, or the Board of Directors or any committee of the Board of Directors (including the Conflicts Committee) or any Affiliates of the General Partner cause the General Partner to make a determination or take or omit to take any action in such capacity, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then, unless another lesser standard is provided for in this Agreement, the General Partner, the Board of Directors, such committee or such Affiliates, shall not make such determination, or take or omit to take such action, in Bad Faith. The foregoing is the sole and exclusive standard governing any such determinations, actions and omissions of the General Partner, the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) and any Affiliate of the General Partner and no such Person shall be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard (all of which duties, obligations and standards are hereby waived and disclaimed), under this Agreement any Group Member Agreement or any other agreement contemplated hereby, or under the Delaware Act or any other law, rule or regulation or at equity. Any such determination, action or omission by the General Partner, the Board of Directors of the General Partner or any committee thereof (including the Conflicts Committee) or of any Affiliates of the General Partner, will for all purposes be presumed to have been in Good Faith. In any proceeding brought by or on behalf of the Partnership, any Limited Partner, or any Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement, challenging such determination, act or omission, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or omission was not in Good Faith.

(b) Whenever the General Partner makes a determination or takes or omits to take any action, or any of its Affiliates causes it to do so, not acting in its capacity as the general partner of the Partnership, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or omit to take such action free of any fiduciary duty or duty of Good Faith, or other duty or obligation existing at law, in equity or otherwise whatsoever to the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who otherwise is bound by this Agreement or any Group Member Agreement or any other agreement contemplated hereby, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in Good Faith or pursuant to any fiduciary or other duty or standard imposed by this Agreement, any Group Member Agreement or any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

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partner under this Agreement, other than when it is “acting in its individual capacity.” For purposes of this Agreement, “acting in its individual capacity” means: (A) any action by the General Partner or its Affiliates other than through the exercise of the General Partner of its authority as a general partner under this Agreement; and (B) any action or inaction by the General Partner by the exercise (or failure to exercise) of its rights, powers or authority under this Agreement that are modified by: (i) the phrase “at the option of the General Partner,” (ii) the phrase “in its sole discretion” or “in its discretion” or (iii) some variation of the phrases set forth in clauses (i) and (ii). For the avoidance of doubt, whenever the General Partner votes, acquires Partnership Interests or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be and be deemed to be “acting in its individual capacity.”

(d) Whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement on the other hand, the General Partner may in its discretion submit any resolution, course of action with respect to or causing such conflict of interest or transaction (i) for Special Approval or (ii) for approval by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates). If any resolution, course of action or transaction: (i) receives Special Approval; or (ii) receives approval of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), then such resolution, course of action or transaction shall be conclusively deemed to be approved by the Partnership, all the Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement, and shall be and be deemed to be duly authorized, legal and binding and to be fair to the Partnership, all the Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any fiduciary or other duty or obligation existing at law, in equity or otherwise or obligation of any type whatsoever.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates or any other Indemnitee shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts or transactions shall be in its sole discretion.

(f) The Partners, and each Person who acquires an interest in a Partnership Interest or is otherwise bound by this Agreement, hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in Good Faith and in accordance with such advice or opinion.

 

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(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its or the Partnership’s duly authorized officers, a duly appointed attorney or attorneys-in-fact.

Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests. As long as any Partnership Interests are held by any Group Member, such Partnership Interests shall not be entitled to any vote and shall not be considered to be Outstanding.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any of its Affiliates (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder”) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, however, that the aggregate offering price of any such offering and sale of Partnership Interests covered by such registration statement as provided for in this Section 7.12(a) shall not be less than $5.0 million; provided further, that the Partnership shall not be required to effect more than two registrations pursuant to this Section 7.12(a) in any twelve-month period; and provided further, however that if the General Partner determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such

 

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offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7 the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) against any losses, claims, demands, actions, causes of action, assessments, damages, liabilities (joint or several), costs and expenses (including interest, penalties and reasonable attorneys’ fees and disbursements), resulting to, imposed upon, or incurred by the Indemnified Persons, directly or indirectly, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus or issuer free writing prospectus as defined in Rule 433 of the Securities Act (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Sections 7.13(a) and 7.13(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be the General Partner, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

 

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(g) The Partnership may enter into separate registration rights agreements with the General Partner or any of its Affiliates.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available to such Partner to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 50 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

 

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(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for U.S. federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Partnership Interest will be deemed to be the lowest quoted closing price of the Partnership Interests on any National Securities Exchange on which such Partnership Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner shall designate the Organizational Limited Partner, or such other Partner as the General Partner shall designate, as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other U.S. federal, state or local law, including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

 

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ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests or the issuance of any Limited Partner Interests in accordance herewith, and except as provided in Section 4.8, each transferee or other recipient of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer or issuance is reflected in the books and records of the Partnership, (ii) shall become bound by the terms of, and shall be deemed to have agreed to be bound by, this Agreement, (iii) shall become the Record Holder of the Limited Partner Interests so transferred or issued, (iv) represents that the transferee or other recipient has the capacity, power and authority to enter into this Agreement, and (v) makes the consents, acknowledgments and waivers contained in this Agreement, all with or without execution of this Agreement. The transfer of any Limited Partner Interests and/or the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Record Holder without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the General Partner or the Transfer Agent. The General Partner shall update its books and records from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section  10.1(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.5(d) who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

 

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ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”):

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi)(A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a limited liability company or a partnership, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Sections 11.1(a)(iv), 11.1(a)(v), 11.1(a)(vi)(A), 11.1(a)(vi)(B), 11.1(a)(vi)(C) or 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on December 31, 2022, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner under the Delaware Act or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on December 31, 2022, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Partners, such withdrawal to take effect on the date

 

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specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the other Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives notice of withdrawal pursuant to Section 11.1(a)(ii), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Partners as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1, unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Partners holding at least 66 2/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Partners holding a majority of the outstanding Common Units (including Common Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the Partners to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the Partners under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Partners under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements

 

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due such Departing General Partner pursuant to Section 7.5, including any employee related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (or its Affiliates) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

Section 11.4 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Partnership Interest becomes a Record Holder of the Partnership Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Partnership Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and such successor is admitted to the Partnership pursuant to Section 10.2;

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(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Sections 11.1(a)(i) or 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Sections 11.1 or 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Sections 11.1(a)(iv), 11.1(a)(v) or 11.1(a)(vi), then, to the maximum extent permitted by law, within 180 days thereafter, a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as the successor General Partner a Person approved by a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of the limited liability of any Limited Partner under the Delaware Act and (y) neither the Partnership nor any successor limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

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Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any other Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

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(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which any class of Partnership Interests are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.7 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or CVR Energy, Inc. or their directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests or any Derivative Instruments pursuant to Section 5.5;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(k) a merger or conveyance pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion and, in declining to propose or approve an amendment, to the fullest extent permitted by law shall not be required to act in good faith

 

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or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. An amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or 13.3, a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of Partners holding a specified Percentage Interest shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of Partners holding the specified Percentage Interest or call a meeting of the Partners to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Sections 13.1 and 13.2, no provision of this Agreement that requires a vote or approval of Partners (or a subset of the Partners) holding a specified Percentage Interest to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of, in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage unless such amendment is approved by the written consent or the affirmative vote of Partners whose aggregate Percentage Interest constitutes not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Sections 13.1 and 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld in its sole discretion.

(c) Except as provided in Section 14.3 or Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Percentage Interests of all Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Partners.

Section 13.4 Special Meetings. All acts of Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting

 

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is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Partnership Interests for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date. For purposes of determining the Partners entitled to notice of or to vote at a meeting of the Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Partnership Interests are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Partners entitled to notice of or to vote at a meeting of the Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transactions of any meeting of Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Partner at a meeting shall constitute a waiver of notice of the meeting, except (i) when the Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened and (ii) that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting. The holders of a majority, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater

 

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Percentage Interest, in which case the quorum shall be such greater Percentage Interest. At any meeting of the Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Partners holding Partnership Interests that in the aggregate represent a majority of the Percentage Interest of those present in person or by proxy at such meeting shall be deemed to constitute the act of all Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Partners holding Partnership Interests that in the aggregate represent at least such greater or different percentage shall be required; provided, however, that if, as a matter of law or amendment to this Agreement, approval by plurality vote of Partners (or any class thereof) is required to approve any action, no minimum quorum shall be required. The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by Partners holding the required Percentage Interest specified in this Agreement. In the absence of a quorum any meeting of Partners may be adjourned from time to time by the affirmative vote of Partners with at least a majority, by Percentage Interest, of the Partnership Interests entitled to vote at such meeting (including Partnership Interests deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Partners owning Partnership Interests representing not less than the minimum Percentage Interest that would be necessary to authorize or take such action at a meeting at which all the Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which Partnership Interests are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Partnership Interests held by the Partners, the Partnership shall be deemed to have failed to receive a ballot for the Partnership Interests that were not voted. If approval of the taking of any action by the Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Partners in connection with a matter approved by the requisite percentage of Partnership Interests acting by written consent without a meeting.

 

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Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of Partnership Interests on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Partners or to act with respect to matters as to which the Partners have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Partners shall be deemed to be references to the votes or acts of the Record Holders of Partnership Interests.

(b) With respect to Partnership Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Partnership Interests are registered, such other Person shall, in exercising the voting rights in respect of such Partnership Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Partnership Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, business trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a general partnership or limited partnership, formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) in accordance with this Article XIV.

Section 14.2 Procedure for Merger or Consolidation.

(a) Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger or consolidation of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Partner and, in declining to consent to a merger or consolidation, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or general or limited partner interests, rights, securities or

 

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obligations of any limited partnership, corporation, trust or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their general or limited partner interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Partners of Merger or Consolidation.

(a) Except as provided in Sections 14.3(d) or 14.3(e), the General Partner, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) or 14.3(e), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of Partners holding a greater Percentage Interest or the vote or consent of a specified percentage of any class of Partners, in which case such greater Percentage Interest or percentage vote or consent shall be required for approval of the Merger Agreement.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or any Group Member under the Delaware Act or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

 

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(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding immediately prior to the effective date of such merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Partners of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Amendment of Partnership Agreement. Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.6 Effect of Merger.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) A merger or consolidation effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 90% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any

 

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Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed or (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. Notwithstanding the foregoing, if, at any time, the General Partner and its Affiliates hold less than 70% of the total Limited Partner Interests of any class then Outstanding then, from and after that time, the General Partner’s right set forth in this Section 15.1(a) shall be exercisable if the General Partner and its Affiliates subsequently hold more than 80% of the total Limited Partner Interests of such class.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and circulated in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment (in the case of Limited Partner Interests evidenced by Certificates), at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Articles IV, V, VI, and XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests (in the case of Limited Partner Interests evidenced by Certificates), and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Articles IV, V, VI, and XII).

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices. Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below.

 

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Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise.

Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery.

An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

The terms “in writing,” “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Partnership Interest, pursuant to Section 10.1(a) without execution hereof.

 

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Section 16.8 Applicable Law; Forum, Venue and Jurisdiction.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper,

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding, and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

Section 16.9 Invalidity of Provisions. If any provision or part of a provision of this Agreement is or becomes, for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby, and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.10 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

 

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Section 16.11 Facsimile Signatures. The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

Section 16.12 Third Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee, and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

 

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

GENERAL PARTNER:
CVR REFINING GP, LLC

By:

 

 

Name:

 

Title:

 

 

LIMITED PARTNER:
CVR REFINING HOLDINGS, LLC

By:

 

 

Name:

 

Title:

 

AMENDED AND RESTATED PARTNERSHIP AGREEMENT

OF

CVR REFINING, LP


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EXHIBIT A

to the Amended and Restated

Agreement of Limited Partnership of

CVR Refining, LP

Certificate Evidencing Common Units

Representing Limited Partner Interests in

CVR Refining, LP

 

No.                 

                 Common Units

In accordance with Section 4.1 of the Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), CVR Refining, LP, a Delaware limited partnership (the “Partnership”), hereby certifies that                          (the “Holder”) is the registered owner of                  Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF CVR REFINING, LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF CVR REFINING, LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE CVR REFINING, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). CVR REFINING GP LLC, THE GENERAL PARTNER OF CVR REFINING, LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF CVR REFINING, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

 

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The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.

 

Dated:                                                                                               

  CVR REFINING, LP

Countersigned and Registered by:                                          

  By:             CVR REFINING GP, LLC

American Stock Transfer & Trust Company, LLC,

As Transfer Agent and Registrar

 

By:

 

 

  Title:  

 

  By:  

 

  Name:  

 

  Title:  

 

 

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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM—as tenants in common

  UNIF GIFT/TRANSFERS MIN ACT

TEN ENT—as tenants by the entireties

                   Custodian                 
JT TEN—as joint tenants with right of
survivorship and not as tenants in common
 

(Cust)                             (Minor)

Under Uniform Gifts/Transfers to CD Minors
Act (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF COMMON UNITS OF

CVR REFINING, LP

FOR VALUE RECEIVED,                  hereby assigns, conveys, sells and transfers unto

 

 

(Please print or typewrite name and address of assignee)

 

 

(Please insert Social Security or other identifying number of assignee)

                 Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                  as its attorney-in-fact with full power of substitution to transfer the same on the books of CVR Refining, LP

 

Date:                                                                                                   NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular. without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15   

 

(Signature)

 

(Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

 

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ANNEX B—GLOSSARY OF SELECTED INDUSTRY TERMS

The following are definitions of certain terms used in this prospectus.

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

backwardation market—Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango market.

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

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

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

bpsd—Abbreviation for barrels per stream day, which refers the maximum number of barrels a refinery may produce over the course of 24 hours when running at full capacity under optimal conditions.

Brent—Brent crude oil, a light sweet crude oil characterized by an API gravity of approximately 38 degrees, and a sulfur content of approximately .4 weight percent.

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

capacity—Capacity is defined as the throughput a process unit is capable of sustaining, either on a barrel per calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as crude oil and other feedstock costs, product values and downstream unit constraints.

catalyst—A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

coker unit—A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke.

contango market—Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation market.

crack spread—A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.

distillates—Primarily diesel fuel, kerosene and jet fuel.

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

 

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feedstocks—Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel during the refining process.

Group 3—A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include our Coffeyville and Wynnewood refineries; the Valero Admore refinery in Admore, OK; HollyFrontier’s Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; ConocoPhillips’ Ponca City refinery in Ponca City, OK; and NCRA’s refinery in McPherson, KS.

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

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

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

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

Mars blend—Mars blend crude oil, a sour crude oil blend characterized by an API gravity of approximately 30 degrees and a sulfur content of approximately 2.0 weight percent

MMBtu—One million British thermal units or Btu: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.

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

NYSE—the New York Stock Exchange.

PADD II—Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.

plant gate price—The unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs.

petroleum coke (pet coke)—A coal-like substance that is produced during the refining process.

rack sales—Sales which are made at terminals into third party tanker trucks.

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

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

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

 

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sweet crude oil—A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

throughput—The volume processed through a unit or a refinery or transported on a pipeline.

turnaround—A periodically required standard procedure to inspect, refurbish, repair and maintain our refineries. This process involves the shutdown and inspection of major processing units and occurs every four to five years.

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

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

WTI at Midland—WTI crude oil priced in Midland, Texas rather than Cushing, Oklahoma.

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

Wynnewood Acquisition—The acquisition by CVR Energy of all the outstanding shares of the Gary-Williams Energy Corporation and its subsidiaries, which owns the 70,000 bpd Wynnewood, Oklahoma refinery and 2.0 million barrels of storage tanks, on December 15, 2011.

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

 

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LOGO

 

 

 

 


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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

 

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the New York Stock Exchange listing fee the amounts set forth below are estimates.

 

SEC registration fee

   $ 81,547   

FINRA filing fee

     90,200   

Printing and engraving expenses

     450,000   

Fees and expenses of legal counsel

     1,250,000   

Accounting fees and expenses

     1,300,000   

Transfer agent and registrar fees

     10,000   

New York Stock Exchange listing fee

     250,000   

Miscellaneous

     68,253   
  

 

 

 

Total

     3,500,000   
  

 

 

 

 

ITEM 14. INDEMNIFICATION OF OFFICERS AND THE DIRECTORS OF THE BOARD OF DIRECTORS OF OUR GENERAL PARTNER.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” is incorporated herein by reference and discloses that we will generally indemnify the directors and officers of our general partner and CVR Energy to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in our partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of CVR Refining GP, LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. We may enter into indemnity agreements with each of the current directors and officers of our general partner to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in our general partner’s limited liability company agreement and to provide additional procedural protections.

The underwriting agreement that we expect to enter into with the underwriters, filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the directors and officers of our general partner.

 

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

In connection with our formation in September 2012, we issued (i) the non-economic general partner interest in us to CVR Refining GP, LLC and (ii) the 100.0% limited partner interest in us to CVR Refining Holdings, LLC for $1,000.00. These issuances were exempt from registration under Section 4(2) of the Securities Act.

 

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On October 23, 2012, CVR Refining, LLC and Coffeyville Finance issued $500 million aggregate principal amount of 6.5% senior notes due 2022 (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 issued the New Notes at face value, and received net proceeds of approximately $492.5 million from the offering, after deducting initial purchasers’ commissions.

There have been no other sales of unregistered securities within the past three years.

 

ITEM 16. EXHIBITS.

See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Exhibit Index is incorporated herein by reference.

 

Item 17. UNDERTAKINGS.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the

Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

The Registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with CVR Refining GP, LLC, our general partner, or any of its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to, CVR Refining GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The Registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the Partnership.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Sugar Land, Texas, on January 8, 2013.

 

CVR Refining, LP
By:  CVR Refining GP, LLC
By:  

/s/ John J. Lipinski

Name:     John J. Lipinski
Title:   Chief Executive Officer, President and Director

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature

  

Title

 

Date

/s/ John J. Lipinski

  

Chief Executive Officer, President and Director of

CVR Refining GP, LLC

(Principal Executive Officer)

  January 8, 2013
John J. Lipinski     

*

  

Chief Financial Officer and Treasurer of

CVR Refining GP, LLC

(Principal Financial and Accounting Officer)

  January 8, 2013
Susan M. Ball     

*

  

Chief Operating Officer and Director of

CVR Refining GP, LLC

  January 8, 2013
Stanley A. Riemann     

*

   Director of CVR Refining GP, LLC   January 8, 2013
Vincent J. Intrieri     

*

   Director of CVR Refining GP, LLC   January 8, 2013
Samuel Merksamer     

 

 

*By:

 

/s/ John J. Lipinski

  John J. Lipinski
  As Attorney-in-Fact

 

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EXHIBIT INDEX

 

Exhibit
Number
  

Description

  1.1*         Form of Underwriting Agreement
  3.1***      Certificate of Limited Partnership of CVR Refining, LP
  3.2***      Form of Amended and Restated Limited Partnership Agreement of CVR Refining, LP (included as Annex A in the prospectus included in this Registration Statement)
  4.1***        Form of Registration Rights Agreement
  5.1*           Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8.1*          Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*          Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC
10.2*          Form of CVR Refining, LP Long-Term Incentive Plan
10.3***      Form of Services Agreement
10.4***      Form of Trademark License Agreement
10.5***      Form of Indemnification Agreement
10.6            Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 to CVR Energy, Inc.’s Form 8-K/A filed on May 23, 2011 (Commission File No. 001-33492))
10.7          

Amended and Restated ABL Credit Agreement, dated as of December 20, 2012, among Coffeyville Resources, LLC, CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as collateral agent and administrative agent (incorporated by reference to Exhibit 1.1 to CVR Energy, Inc.’s Form 8-K filed on December 27, 2012 (Commission File No. 001-33492))

10.7.1       

Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by reference to Exhibit 1.2 to CVR Energy, Inc.’s Form 8-K filed on December 27, 2012 (Commission File No. 001-33492))

10.8***      Form of Intercompany Credit Facility
10.9            Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007 (Commission File No. 001-33492))
10.10          Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011 (Commission File No. 001-33492))
10.11          Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007)

 

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Exhibit
Number
  

Description

10.12            Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 of the Form 10-K filed by CVR Energy, Inc. on March 28, 2008 (Commission File No. 001-33492))
10.13            Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 of the Form 10-Q filed by CVR Energy, Inc. on August 14, 2008 (Commission File No. 001-33492))
10.14            Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011 (Commission File No. 001-33492))
10.15            Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007 (Commission File No. 001-33492))
10.16***†    Amended and Restated Crude Oil Supply Agreement dated August 31, 2012, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC
10.17***†    Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC
10.18++        Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and John J. Lipinski (incorporated by reference to Exhibit 10.16 of the Form S-1/A of CVR Partners, LP filed on January 28, 2011 (Commission File No. 001-35120))
10.19++        Third Amended and Restated Employment Agreement, dated as of July 27, 2012, by and between CVR Energy, Inc. and Susan M. Ball (incorporated by reference to Exhibit 10.1 of CVR Energy Inc.’s Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012) (Commission File No. 001-33492))
10.20++        Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Stanley A. Riemann (incorporated by reference to Exhibit 10.18 of the Form S-1/A filed by CVR Partners, LP on January 28, 2011 (Commission File No. 001-35120))
10.21++        Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edmund S. Gross (incorporated by reference to Exhibit 10.4 to the CVR Energy, Inc.’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011 (Commission File No. 001-33492))
10.22++        Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.5 to the CVR Energy, Inc.’s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011 (Commission File No. 001-33492))
10.23            Indenture relating to 6.500% senior secured notes due 2022, dated as of October 23, 2012, by and between CVR Refining, LLC, Coffeyville Finance Inc., each of the guarantors party thereto, Wells Fargo Bank, National Association, as Trustee, and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed by CVR Energy, Inc. on October 29, 2012 (Commission File No. 001-33492))

 

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Table of Contents
Index to Financial Statements
Exhibit
Number
  

Description

10.24            Registration Rights Agreement relating to 6.500% senior secured notes due 2022, dated as of October 23, 2012, by and between CVR Refining, LLC, Coffeyville Finance Inc., Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and the other parties thereto, (incorporated by reference to Exhibit 4.2 of the Current Report on Form 8-K filed by CVR Energy, Inc. on October 29, 2012 (Commission File No. 001-33492))
10.25*          Form of Reorganization Agreement
21.1***       List of Subsidiaries of CVR Refining, LP
23.1*           Consent of KPMG LLP
23.1.1*        Consent of KPMG LLP
23.2*           Consent of Deloitte & Touche LLP
23.3*         Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.4*         Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1***       Powers of Attorney
99.1***       Consent of Carl C. Icahn, Director Nominee
99.2***       Consent of Daniel A. Ninivaggi, Director Nominee
99.3***       Consent of SungHwan Cho, Director Nominee
99.4***       Consent of Glenn R. Zander, Director Nominee
99.5***       Consent of Jon R. Whitney, Director Nominee
99.6***       Consent of Keith Cozza, Director Nominee
99.7***       Consent of Kenneth Shea, Director Nominee

 

* — Filed herewith.
*** — Previously filed.
— Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request     for confidential treatment.
++ — Denotes management contract or compensatory plan or arrangement.

 

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